Energy International, Inc./Gastec Technology BV Report No. 02-1119-BR0022-V3
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This report, examines in detail the structure, operation and regulatory background of four natural gas system operators in those countries that have introduced a competitive and unbundled gas market.
The USA, was the first to initiate this process, when in 1995, the Government introduced an order that was designed to produce the separation of gas transportation from all other gas related marketing activities. However, with over 100 pipelines in the USA, the speed of change was not fast enough and the Government subsequently made ‘unbundling’ a mandatory requirement.
The UK followed soon after, with the privatisation of British Gas and the Gas Act of 1986 that established competition, firstly in the domestic market and then for the industrial and commercial market. Unlike the USA, the UK had a single, fully integrated gas monopoly, namely the British Gas Corporation (BGC). In the UK, the emphasis has been firstly on reducing gas prices, followed by the break-up and the unbundling of the BGC structure.
By comparison, Australia’s utilities, including natural gas, were a mixture, with many being Government owned and in some cases vertically integrated monopolies. The Government decided, where possible, to promote competition through the structural reform of public monopolies and by legislative reform. A wholesale gas market was introduced, commencing operation in March 1999, with the establishment of an independent transmission system and market operator.
With these backgrounds, and the establishment of Regulators to enforce the legislation, the four system operators of the natural gas pipelines conduct their business. Whereas the day-to-day operation of the gas transmission system has many similarities – e.g. gas allocation, nominations, balancing, gas trading - the size, structure, geographical areas and the role of the Regulator lead to differences in the framework under which the companies have to operate.
The study demonstrated that all the balancing systems considered exacted some form of penalty on shippers for trading out of balance. The US systems exact penalties, which are based generally on the product of a predetermined penalty rate and a volume imbalance i.e. fixed / sliding rates. The Australian and UK systems considered tended to depend on ‘market driven’ penalty costs i.e. variable rates.
The objective of this study is to explain and put into perspective these differences.
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The European Council is preparing a proposal to amend the European Gas Directive. In this proposal, there will be an obligation for every European Union member state to introduce a System Operator (SO) for its natural gas transportation network. The Dutch government is exploring the possibility of introducing a SO in the Netherlands, and is investigating the role of system operators in other countries as part of that process. This project examines four system operators responsible for important transmission networks in three countries with liberalized natural gas markets – two in the United States (US), and one each in the United Kingdom (UK) and Australia.
The four system operators are as follows:
• Alliance Pipeline L.P. (USA) • Nicor Gas (USA) • Transco (UK) • VENCorp (Australia)
This study provides an overview (corporate, geographic, and operational) of each SO, and describes their responsibilities, roles and functions. It concludes with a comparative analysis of the operational frameworks within which they operate.
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The driving force behind the regulation of the gas industry in the USA, which began some fifteen years ago and was, based on the conclusion that separating or ‘unbundling’ the gas commodity from interstate transportation was an essential element of vibrant competition. The regulatory body that was set up is Federal Energy Regulatory Commission (FERC), which is an independent regulatory agency of the U.S. government.
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• A U.S. Government Agency • Independent Executive Branch Agency • Decisions subject to review by U.S. Courts • 5 Voting Commissioners, appointed by the President, confirmed by the Senate, five-Year Terms • Around 1250 Employees o Engineers, Technical Specialists o Lawyers o Economists
FERC regulates rates, terms and conditions of service for over 100 interstate natural gas pipelines and it also approves the siting and construction of pipeline facilities, including the environmental review.
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The restructuring process began in 1985 with a transitional program that allowed and encouraged unbundled transportation, but did not require it. Prior to 1985:
• Natural gas producers sold gas to interstate pipelines • Pipelines sold bundled product (natural gas and transportation capacity) to Local Distribution Companies (LDCs)
In 1992, the Commission adopted Order No. 636, based on our conclusion that a more aggressive regulatory framework was needed to achieve a truly open and competitive market for natural gas. The cornerstone of this Order was its requirement that all interstate pipelines eliminate their bundled sales services and allow third-party access without discrimination.
In the United States, the jurisdictional split between the federal and state governments makes it difficult to develop a coherent and consistent regulatory policy. The FERC has jurisdiction over wholesale transactions and interstate transportation. Each of the 50 states has a regulatory commission with jurisdiction over local distribution and end use transactions. They are not subject to FERC authority.
In the era of unbundled services, natural gas marketers have emerged as important participants in the market. In fact, gas marketers are replacing the local distribution companies as the primary owners of firm pipeline capacity. The marketers also provide a variety of hedging and other portfolio management services that make them key strategic players.
By the time regulation came into force, pipeline companies had already begun to create affiliated companies, namely marketers and brokers who buy and sell market priced gas. The creation (QHUJ\,QWHUQDWLRQDO,QF 4 %59 of pipeline marketing affiliates raised the question as to how could the FERC ensure that the pipeline would not use its monopoly control over the physical pipeline system to discriminate in favor of its affiliated marketer. Ultimately, the FERC chose to adopt rules that seek to prevent potentially abusive behavior by pipelines and their marketing affiliates rather than tougher remedies, such as complete divestiture. The FERC considers that, although there have been a few complaints of favoritism; this system has proven to be a reasonable balancing of all interests involved.
The restructuring of the natural gas industry in the USA has achieved:
• Robust competition for natural gas supply • Increases in natural gas use • Financially healthy pipelines • Availability of innovative and non-discriminatory pipeline services • Reliable and reasonably priced natural gas and pipeline services • Development of scores of market hubs and pooling points • Commoditisation of natural gas • Integration of North American natural gas market • Electronic communication via Internet
Recently however, the FERC has been criticized for its failure to protect consumers when markets spiraled out of control in the Western United States. This, together with the debacle over the Enron trading strategies has called into question the integrity of energy marketing and trading. Critics in Congress have denounced power suppliers for market manipulation, and the Commission for ineffective monitoring and intervention, and for failing to uncover such activity until now. Two General Accounting Office reports published in June questioned the Commission’s readiness to deal effectively with market dysfunctions.
In February 2002 the FERC initiated a thorough investigation of Western market manipulation. The Commission has also embarked upon a multi-pronged strategy to restore necessary confidence. Refunds have been ordered for customers who suffered from the out of control prices in western markets.
The FERC has now created a new market monitoring and investigations unit to act as an early warning system, to advise the Commission immediately, if a market is spinning out of control. The FERC remains committed to a market-based approach, but vigilance, monitoring, effective remedies and customer protection are the keywords at the moment.
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The Alliance Pipeline system is a new natural gas pipeline system designed to initially offer 37.5 X 106 cubic meters per day of firm delivery service from the gas-producing areas of northeastern British Columbia and northwestern Alberta to markets in the mid-western United States and eastern Canada.
Alliance LP Inc. is a partnership of Duke Energy Corp, El Paso Corp., Enbridge Inc., Fort Chicago Energy Partners LP. Alliance own and operate their pipeline and are responsible for its physical maintenance.
Alliance Pipeline L.P. (Alliance USA) is a US limited partnership formed under the laws of the State of Delaware. It is the owner and system operator of the US portion of Alliance Pipeline’s transmission system, extending from an interconnection with Alliance Pipeline Limited Partnership (Canada) at the Canadian-United States border to various points of delivery in the Chicago, Illinois area. In 2001, Alliance USA delivered 2.5% of U.S. gas consumption.
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A timeline of the development of the Alliance Pipeline system and commencement of Alliance-USA’s functions as system operator is given below.
• May 10, 1996: Alliance Pipeline Limited Partnership and Alliance L.P. agreements signed • June 10, 1996: Formal announcement of project • December 24, 1996: Application filed with the U.S. Federal Energy Regulatory Commission (FERC) • July 3, 1997: Application filed with the Canadian National Energy Board (NEB) • September 16, 1998: Regulatory approval from FERC • December 3, 1998: Regulatory approval from NEB • May 15, 1999: Mainline construction begins - U.S. side • June 15, 1999: Mainline construction begins - Canadian side • November 29, 1999: Canada-U.S. tie-in merged at border • August 26, 2000: Mainline construction completed • September 6, 2000: First ‘test’ gas flows through system into Chicago area • December 1, 2000: Commercial service begins
4.2.1. Corporate Structure
The Alliance Pipeline corporate structure is made up of two components:
• Alliance Pipeline Limited Partnership (a Canadian entity) through its General Partner, Alliance Pipeline Ltd., owns and operates about 2,320 km of pipeline (mainline and laterals) and appurtenant facilities in Canada
(QHUJ\,QWHUQDWLRQDO,QF 6 %59 • Alliance Pipeline LP (an American entity) also known as Alliance USA, through its Managing General Partner, Alliance Pipeline Inc., owns and operates about 1,405km of pipeline (mainline and delivery) and appurtenant facilities in the U.S.
As operator of the system in the US, Alliance USA’s functions are carried out by three groups who collectively oversee the transportation of gas from northeastern British Columbia and northwestern Alberta to the Chicago area. They are:
• Customer Service Group • Gas Control Group • Technical Support Group
The responsibilities of each group are as follows:
• The Customer Service Group acts as the liaison between the shippers and Alliance Pipeline to ensure their shipping requirements and obligations to the pipeline company are met. • The Gas Control Group oversees the actual physical transportation of gas from the point at which it enters the Alliance Pipeline system (receipt point) to the terminus (delivery point) near Chicago. • The Technical Support Group has the task of ensuring that all the state-of-the-art equipment installed throughout the system is maintained and operating effectively at all times.
4.2.2. Autonomy
As a company engaged in the business of transporting natural gas for shippers in interstate commerce, Alliance USA is under the jurisdiction of the Federal Energy Regulatory Commission.
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4.3.1. Geographical Service Territory
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(QHUJ\,QWHUQDWLRQDO,QF 7 %59 The US portion of the Alliance Pipeline transmission system operated by Alliance USA has the following characteristics:
• 1,429 km of high-pressure pipeline in the US • Receipt point at interconnection with Alliance Pipeline Limited Partnership in Renville County, North Dakota • 7 compressor stations spaced about 193 km apart • Firm capacity of 37.5 X 106 cubic meters plus additional interruptible capacity • 5 downstream interconnection delivery points to: ANR Pipeline Company, Midwestern Gas Transmission Company, Natural Gas Pipeline Company of America, Northern Illinois Gas Company and People’s Gas Light and Coke Company - located in Grundy and Will Counties, Illinois • One interconnection delivery point at the Aux Sable Liquid Products L.P. gas processing plant
4.3.2. System Operation
Alliance USA offers capacity on the Alliance Pipeline system under the following agreements:
• Firm Transportation: Most of Alliance USA’s transportation activities arise from obligations associated with firm transportation contracts. Alliance USA has a certificated design capacity of 42.8 X 106 cubic meters per day, but commenced operations on December 1, 2000 with contracted firm capacity of 37.5 X 106 cubic meters per day. o Firm contracts are 15-year ‘Ship or Pay’ contracts. Shippers are charged regardless of utilization. o Regulated tariff allows for 100% recovery of demand costs and has a component subject to negotiations between the shipper and the system operator. Negotiated rates may apply to all or a portion of the capacity and/or the entire or some portion of the term. • Interruptible Transportation: Shippers may contract with Alliance USA for daily quantities of gas up to a Maximum Daily Transportation Quantity (MDTQ), which is specified in the agreement. • Authorized Overrun Service (AOS): From time to time, Alliance USA offers unsubscribed transportation capacity, the amounts of which will vary depending upon system availability and shipper nominations for firm service at that time. AOS quantities are offered to holders of firm capacity prorated according to their share of contracted capacity. They are charged only the incremental cost of the fuel. • Capacity Release: A secondary market for capacity is created by the release of contracted capacity held by shippers under Firm Transportation Agreements. The release capacity can be sold under private agreement between parties or awarded to bidders through an auction process.
4.3.3. Market Parties
The primary market consists mainly of shippers who have contracted with Alliance USA for firm capacity, and smaller participants who are shippers on interruptible contracts. Secondary market parties are made up of entities pre-approved by the system operator to bid for capacity released by primary shippers.
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Shippers are bound by the terms of either a Firm Transportation Agreement or an Interruptible Transportation Agreement signed with the system operator.
Secondary Market Participants
• In order to participate in the secondary gas market for released capacity, a prospective market participant must be listed on Alliance USA’s Approved Bidders List. To be added to the Approved Bidders List, the party’s corporate and credit information must meet with the approval of the system operator, who will also establish the financial limits for that entity’s transactions • The approved bidder must then sign a Master Capacity Release Agreement whereby the replacement shipper agrees to be bound by the terms of its winning bid or the terms of any Pre-Arranged Capacity Release. The replacement shipper’s rights however cannot exceed those of the releasing shipper • For each award of capacity, Alliance USA electronically submits a Capacity Release Schedule to the replacement shipper, with all the terms of the transaction
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4.4.1. Capacity Booking
Alliance USA allows shippers who have signed a Firm Transportation Agreement, Interruptible Transportation Agreement, or Master Capacity Release Agreement, to receive service through a nomination process. Via the internet, potential shippers can initially determine the available capacity on the Alliance Pipeline system and then nominate and confirm next-day transportation of specified quantities of gas. These nominations are carried out on a daily basis.
Specifics of the process are as follows:
• All nominations are made on Alliance USA’s EDM system (see Section 4.5.1) according to fixed formats and protocol requirements. • To receive service, a shipper can submit daily nominations specifying desired beginning and end dates for transportation of specified quantities of gas to be delivered: o From specified receipt point(s) to specified delivery point(s) on the Alliance Pipeline system o To the processing delivery point, if desired o From the shipper's U.S. Receipt Pool to the U.S. Receipt Pools of other parties and vice versa (title transfer) o From the shipper's U.S. Delivery Pool to the U.S. Delivery Pools of other parties and vice versa (title transfer) • Shippers can make changes to nomination designations on the EDM • Alliance USA will accommodate nomination requests based on system availability and established priorities (see Section 4.4.2 for details)
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As system operator, Alliance USA is responsible for effectively scheduling transportation capacity to maximize throughput (the volume of gas being transported) while maintaining the safety of the system at all times. The scheduling responsibilities are undertaken by Alliance’s Customer Service Group (CSG) whose responsibilities are as follows:
• To implement and monitor all day-to-day aspects of the actual transportation of gas • To provide monthly reporting and invoicing for the transportation service provided • To build and maintain relationships with the Receipt Point Operator1 as well as downstream pipeline operators2. • To maintain the interests of the shipper by serving as a single point of contact for the shipper from the receipt point to the delivery point
The functions of the CSG are as follows:
• Customer Service representatives (CSR) use GMS (Gas Management System) software to monitor and implement the daily transportation flow of gas on the Alliance Pipeline system and to schedule the quantities of gas being shipped. • When a nomination is received, the CSR confers with members of the Gas Control Group to determine whether there is sufficient capacity to transport the quantity of gas nominated by the shipper. • Working with Gas Control Group, the CSR will determine whether all or only part of the nomination can be transported the next day. • Customer Service then confirms with upstream and downstream pipeline operators to ensure the gas can move on their pipelines. • Once the quantity of gas to be shipped has been determined, the CSR advises the shipper of the arrangements. • The CSR then uses The EFM (Electronic Flow Measurement) system to record the actual amount of gas moved at each location. This information is used to monitor shipper transactions and to prepare and issue invoices for the cost of shipping the agreed-upon quantity of gas during a particular month.
Transportation capacity is then scheduled in the following order of priority:
1. Firm Transportation quantities within shippers' contracted capacities 2. Authorized Overrun Service quantities for shippers under Firm Transportation Agreements 3. Interruptible Transportation quantities allocated on the basis of rate paid, from highest to lowest, with pro rata allocation when the rate paid is equal
In the event of curtailment, the reverse order of priorities is followed.
1 A company that operates the production plant immediately upstream of where the shipper’s gas enters the Alliance Pipeline system 2 Companies which take the gas exiting the system for distribution locally or to a more distant destination’
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As system operator, Alliance USA’s major functions include gas balancing and pipeline monitoring and control. As part of the nomination procedure, Alliance USA communicates to all shippers the current acceptable level of tolerance for imbalances. In general, tolerance of periodic imbalances up to 4% of the quantity scheduled by the system operator is allowed.
On any one-day, energy imbalances on shipper accounts can occur. Shippers who incur imbalances are subject to the following actions:
• When imbalances occur, Alliance USA may adjust new or standing nominations to bring a shipper's account within the specified tolerance levels and the shipper may be asked to take action to eliminate the imbalance. • In the event the energy imbalance exceeds the tolerance specified by Alliance USA on any day, the shipper will be subject to an Energy Imbalance Penalty.
Alliance USA balances gas flow on a daily basis by fluctuating line-pack levels (the amount of gas in the line at any point in time) and manipulating operational balancing agreements with interconnecting facilities. The Gas Control Group (GCG), from its control center located in Calgary, Alberta, is able to remotely monitor and control the pipeline at any point along the route using state- of-the-art equipment. Operators are on duty 24 hours a day, seven days a week, 52 weeks a year. The system operator executes its balancing, monitoring, and controlling functions in the following way:
• The SCADA (Supervisory Control and Data Acquisition) computer program is used to monitor pressure, temperature, flow and other key operational information every few seconds, via satellite. SCADA provides a continuous real-time view of the condition of the entire pipeline system3. • Each gas day, the GCG can issue SCADA commands to open or close valves, start, stop, speed up, or slow down compressors to manage the line-pack on the system to ensure gas is received and delivered reliably and safely. • Real Time Model (RTM), a computer software package that simulates hydraulic operation of the pipeline, is used to further ensure safe operation of the pipeline. Its primary purpose is to detect leaks, track the composition and dew point of the gas, and continually calculate the line-pack of the pipeline. • Using the RTM and SCADA systems, GCG is also able to accurately predict the composition of the gas as it arrives at the compressor stations and monitor the quality of gas entering the pipeline at any entry point in the system all the way to Chicago.
4.4.4. Capacity Trading Service
A shipper who has signed a Firm or Interruptible contract with Alliance USA may release unwanted capacity to be auctioned among bidders who have been pre approved by system operator. This creates a secondary market for natural gas transportation on the Alliance Pipeline system. There are two exceptions to the bidding process: • Pre-Arranged Releases: For capacity available for a period of thirty-one days or less, a shipper may release the capacity without subjecting it to bidding. Alliance USA must be notified via the EDM of such release.
3 From the meter stations which measure the amount of gas entering, to the compressor stations which enable the movement of the gas through the pipeline, to the control valves in Chicago that direct the amount of gas to the appropriate pipeline interconnection. (QHUJ\,QWHUQDWLRQDO,QF 11 %59 • Permanent Releases: A shipper with an existing Firm Transportation Agreement with Alliance USA may release its entire capacity to a third party for the remaining term of the contract. The third party must execute a new Assignment Novation Agreement with Alliance USA.
The logistics of the capacity trading process are as follows: • The releasing shipper may specify the starting and ending dates and times for the bidding period. • On any day, a prospective replacement shipper may make multiple simultaneous bids for capacity. The aggregate of these bids may exceed the shipper’s bid limit. • If the replacement shipper receives multiple capacity awards that in aggregate exceed its bid limit: o The replacement shipper’s bid limit will be reduced to $0.00 and the shipper must post a Letter of Credit or cash deposit within 7 days in an amount equal to or greater than the difference between the original bid limit and the financial obligation of the awarded capacity. o If the replacement shipper fails to comply, the awarded capacity in invalidated and reverts back to the releasing shipper
4.4.5. Storage, Parking, and Loaning Services
Alliance USA does not offer any gas storage, parking, or loaning services.
4.4.6. Risk Management Service
Alliance USA does not provide risk management services and has not developed the infrastructure for market parties to engage in any risk management activities.
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4.5.1. Informational Services
Alliance USA has established a proprietary information dissemination tool called the Electronic Delivery Mechanism (EDM) that is accessible only to contractors and subscribers. The EDM is available twenty-four hours per day, and is used for a variety of purposes including gas nomination and electronic execution of contractual agreements. It is also the medium by which Alliance USA provides a very broad range of information including (but not restricted to) the following:
• Information or services required by the FERC • Vital information related to Alliance USA operations such as: • Total contracted capacity under all Firm Transportation Agreements • Availability of AOS capacity • Notices of any restrictions of interruptible capacity • Capacity releases • Completed capacity release transactions • Operational reports • Transactional reports
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On or before the 9th day of each month, Alliance USA’s Customer Service Group issues invoices to shippers for amounts payable for the preceding delivery month under applicable rate schedules(s) plus any additional charges, penalties, or credits due. All payments by shippers have to be made in US funds by electronic funds transfer to a depository designated by the system operator.
In addition to transactional services performed for firm and interruptible customers, Alliance USA also facilitates the exchange of gas ownership associated with the release and resale of capacity.
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The Chicago Hub has emerged as a major natural gas supply hub feeding the industrial Midwest and Eastern United States with supplies from the Gulf Coast, Southwestern US, the Rocky Mountains, and Western Canada. The most recent project to increase gas supplies to the Hub is the Alliance Pipeline, which began delivering gas into Chicago in 2000.
Nicor Organogram
Nicor Inc.
Nicor Gas
Nicor Hub Services
Nicor Enerchange Trading Nicor Enerchange Hub Administration
5.1.1. Nicor Hub Services
Nicor Hub Services operates two divisions within Nicor Enerchange LLC, Nicor Enerchange Trading and Nicor Enerchange Hub Administration.
1LFRU(QHUFKDQJH7UDGLQJ Was created in 1998, and is a wholesale natural gas marketing company that offers customized energy management solutions for its customers.
As one of the largest natural gas providers in the Midwest with customers in Illinois, Wisconsin, Indiana, Iowa and Michigan, its success is a direct result of wholesale trading expertise and market knowledge of the Midwest.
Nicor Enerchange Trading works with large volume gas end-users and utility companies helping them in the areas of energy management, asset optimization and risk management. It claims that its strength lies in buying and selling natural gas on multiple gas pipelines at multiple locations.
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Nicor Enerchange Hub Administration operates as a center for gas transportation solutions, Nicor Enerchange Hub Administration, commonly referred to as the "Chicago Hub", offers customers new alternatives in natural gas transportation services.
(QHUJ\,QWHUQDWLRQDO,QF 14 %59 The Chicago Hub is the link to a vast network of natural gas resources. Nicor has direct connections with six major interstate pipelines including ANR Pipeline Company (ANR), Natural Gas Pipeline Company of America (NGPL), Northern Border Pipe Line (NBPL), Northern Natural Gas Company (NNG), Midwestern Gas Transmission Company (TGP/Midwestern) and Panhandle Eastern Pipeline Company.
Excess storage capacity is managed on behalf of Nicor Gas, maximizing the value of its assets. Nicor’s services are provided at negotiated rates based on current market conditions.
Nicor Gas has seven underground storage facilities.
Nicor claims to be exceptional in the Midwest in terms of its offering - pipeline connectivity and storage capability. Nicor claims to be able to eliminate pipeline imbalance penalties and offer efficient transactions.
5.1.2. History
Nicor Gas (hereafter referred to as ‘Nicor’) serves nearly 5.7 million customers in the northern third of Illinois (excluding the city of Chicago) and the metropolitan area surrounding the city of Chicago. Since its formation in 1954, it has grown to become the largest natural gas distribution company in Illinois and one of the largest in the nation. It also transports and stores natural gas for nearly 129,000 commercial, industrial and residential customers in the state who purchase gas from other suppliers. Nicor Gas is the owner and system operator of the Chicago Hub.
5.1.3. Corporate Structure
Nicor’s operation of the Chicago Hub is conducted by its division Nicor Hub Services, which consists of two affiliates:
• Nicor Enerchange Trading: This is a wholesale natural gas marketing company created by Nicor Gas in 1998. It offers large-volume gas end-users and utility companies energy management, asset optimization, and risk management services.
• Nicor Enerchange Hub Administration: System administrator of the Chicago Hub
5.1.4. Autonomy
Nicor’s intrastate activities are under the jurisdiction of the Illinois Commerce Commission while its interstate activities are regulated by the Federal Energy Regulatory Commission (FERC).
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5.2.1. Geographical Service Territory
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Nicor Gas owns and operates a 17,500 km natural gas distribution system, which has more than 90 interconnections with 7 interstate natural gas pipelines. It is also the owner and operator of the Chicago Hub. The Hub has direct connections with five major interstate pipelines (additional pipelines are also being proposed):
• ANR Pipeline Company (ANR) • Natural Gas Pipeline Company of America (NGPL) • North Border Pipe Line (NBPL) • Northern Natural Gas Company (NNG) • Midwestern Gas Transmission Company (TGP/Midwestern)
In addition to access to multiple pipelines, Nicor also has large underground storage aquifers that lie beneath northern Illinois’ farmland. Its storage system of approximately 4.6 X 109 cubic meters is one of the largest in the industry. Nicor can meet about 50-60% of its peak-day needs and about one-third of its annual deliveries with natural gas from storage.
5.2.2. System Operation
As system operator of the Chicago Hub, Nicor oversees services that include short-term interruptible gas transportation4 and wheeling5, storage, and park-and-loan transactions. In addition to interruptible services, Nicor may from time to time, have limited storage and transportation capacity that it offers to shippers on a firm basis, but only for defined periods of time.
4 Transportation is the movement of gas from one point to another on a pipeline where either the receipt or delivery point is not an interconnected pipeline. 5 Wheeling is the transfer of gas from one interconnected pipeline to another through the transmission system of a market center pipeline (hub transfer). (QHUJ\,QWHUQDWLRQDO,QF 16 %59 Major services offered by Nicor are as follows:
• Gas moving: The Hub has access to gas supplies from Canada and the Mid-Continent, Gulf Coast, and Midwestern United States. Gas going through the Hub can be routed to other markets as well as back to the producing areas. • Gas parking: For customers who have extra gas at Nicor’s entry points, the Hub offers the possibility of temporary storage in one of Nicor’s seven underground storage facilities. • Gas loaning: The Hub offers short-term interruptible gas loans that can help customers take advantage of market situations.
The rates for transportation/wheeling and storage are subject to negotiations between Nicor and the shippers, but they cannot exceed the limits established by the FERC and the Illinois Commerce Commission.
All transportation/wheeling and storage gas received by Nicor at the Hub is accounted for on a daily basis. If a customer’s demand for gas exceeds its supply and the imbalance cannot be adequately met by the customer’s withdrawal rights from storage, Nicor will supply the difference. This ‘Authorized Use’ gas will be billed to the customer at the system operator’s cost of gas6. Beyond these quantities, any Nicor-owned gas required to correct further imbalances is classified as ‘Unauthorized Use’ gas, and is subject an additional charge of US $0.26/kWhr.
In order to maintain the operational integrity of the company's system, Nicor Gas may declare certain days as ‘Critical Days’:
• Nicor Gas will post a notice on the company's electronic bulletin board and on a recorded dial-in message at least 28 hours before the start of the Critical Day. • When a Critical Day occurs, shippers can change their nominations until four hours before the start of the Critical Day. • Storage withdrawals will be limited on a Critical Day.
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In the USA TSO’s are allowed by FERC to declare critical days. These critical days impose restrictions on the shippers. The Nicor definition of a critical day is as follows:
A Critical Day can be declared whenever it is necessary to maintain the operational integrity of the system. Nicor Gas may declare a Critical Day when any of the following five conditions occurs or is anticipated to occur:
• Nicor experience failure of transmission, distribution, gas storage or gas manufacturing facilities.
• Transmission system pressures or other unusual conditions jeopardize the operation of the system.
• Transmission, storage and supply resources are being used at or near their maximum rated deliverability.
• Transporters or suppliers call the equivalent of a Critical Day.
6 Commodity cost of gas plus other operation and maintenance costs (QHUJ\,QWHUQDWLRQDO,QF 17 %59 • Nicor is unable to fulfill its firm contractual obligations or it is necessary to maintain the overall operational integrity of all or a portion of the system
Critical days can only be called from November 1st. to April 30th.
5.2.3. Market Parties
Market participants of the Chicago Hub are shippers who contract with Nicor to move gas between any of the pipelines that are interconnected with the company.
5.2.4. Obligations and Interdependence of Market Parties
FERC rules dictate that Nicor’s responsibilities as system operator of the Chicago Hub are subordinate to its obligations as a natural gas distribution company within the State of Illinois. As such, firm distribution and storage services provided within the state take first priority, and transportation/wheeling and storage services offered by the Hub to shippers must predominantly be of an interruptible nature. From time to time, however, firm transportation/wheeling and storage services may be offered if Nicor determines that it is able to provide these services without impairing its ability to fulfill its intrastate firm obligations.
Shippers are responsible for making necessary arrangements to move their gas away from the Hub. Daily volumes that are not moved away from the Hub are put into the Hub’s storage facilities and will be considered part of the shippers’ storage capacity.
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5.3.1. Capacity Booking
Hub customers must sign a Hub Service Agreement with Nicor prior to receiving service. They can then proceed to schedule service with Nicor on a day-by-day or advance-day basis. Shippers may nominate to inject, withdraw, move, or transfer gas. Each nomination is considered to be a separate transaction and requires signing of a Hub Transaction Request and Agreement Form. Nominations may be made through the following media:
• Electronic system: Requests may be made on Nicor’s Gas Exchange (see Section 5.4.1) • E-mail: Requests may be submitted and responses guaranteed within one business day • Telephone: Transportation customer service call center (630-983-4040, Option 1) is open Monday-Friday 8:00-4:30 to take requests • Fax: Contracts may be sent and received via fax
All gas supplies purchased and/or sold at a Nicor Gas entry point may be subject to full curtailment unless nominations are submitted by a designated time deadline on the business day prior to gas flow. No nominations may exceed the limits prescribed by the Hub Transaction Request Form.
(QHUJ\,QWHUQDWLRQDO,QF 18 %59 5.3.2. Scheduling Service
All transportation/wheeling and storage gas received by Nicor is accounted for on a daily basis and rescheduled for eventual redelivery to a designated delivery point. Nicor schedules transportation/wheeling and storage services according to the following order of priority: 1. Firm transportation/wheeling and storage services 2. Priority interruptible transportation/wheeling and storage services7 3. Interruptible transportation/wheeling and storage services
Interruptions and curtailments are executed in the reverse priority order followed for gas scheduling.
5.3.3. Balancing Service
Customers selecting unbundled transportation/wheeling services will have their use and nominations balanced daily through the use of recording devices installed by Nicor. The recording device requires a telephone line, which must be provided by the customer.
On any non-critical day, if a customer demand exceeds its supply, Nicor corrects the imbalance by obtained using gas from the following sources, in the order of priority listed:
1. Customer-owned gas withdrawn from storage 2. Company supplies under for firm customers’ FBS only (see Section 5.3.5) 3. ‘Authorized Use’ gas (Nicor-owned gas) 4. ‘Unauthorized Use’ gas (Nicor-owned gas)
On a Critical Day, gas is balanced in the same manner, but with the following restrictions:
• Only 2.3% of a customer’s SBS capacity can be withdrawn from storage • ‘Authorized Use’ gas is limited to Nicor supplies up to the remainder of unused SBS withdrawal rights
5.3.4. Capacity Trading Service
Buyers and sellers can trade gas and capacity and/or facilitate direct negotiations for legally- binding transactions on Nicor Gas’ electronic-based Gas Exchange system.
5.3.5. Storage, Parking, and Loaning Services
Storage Banking Service (SBS)
Nicor assists shippers in balancing their daily needs by providing gas storage services, which are available under different agreements:
7 Priority interruptible services are distinguished from interruptible services in that priority transportation /wheeling and storage customers must prepay 50% of their applicable rates.
(QHUJ\,QWHUQDWLRQDO,QF 19 %59 • Shippers can contract for SBS capacity and select the levels of storage desired. A minimum of one MDCQ-day is required and a maximum of 26 MDCQ-days is available to all customers8. On Critical Days, withdrawals will be limited to 2.3% of the customer’s SBS capacity. • Firm customers can sign up for Firm Backup Service (FBS). This entitles them to specific contracted amounts of Nicor-supplied gas on any day. On a Critical Day, Nicor will supply the FBS in addition to the 2.3% of the customer’s SBS capacity.
A shipper’s daily net balance in storage is the difference between receipts of gas from the shipper delivered to the storage facility and Nicor’s delivery to the shipper that is withdrawn from storage on that particular day.
Excess Storage
When a customer’s storage capacity is 5% or more of the SBS capacity in any monthly billing period, Nicor charges an excess storage fee of US $0.003/kWhr. This fee is applied to the maximum amount of gas over the customer’s bank capacity in that billing period.
Storage Balance Transfer
A gas owner may request to transfer excess storage balance at the end of a billing month to another party. The request may be submitted up to 20 days after the bill (with the excess storage charge) is issued. The transferring party will be assessed a US $35 transaction fee.
Parking and Loaning Services
As system operator, Nicor offers parking and loaning services to shippers, subject to available capacity. Any shipper requesting such service must sign a Hub Service Agreement and each transaction is executed by filling in a Hub Transaction Request Form specifying the following information:
• Day(s) on which shipper wishes to park gas on Nicor’s system or re-deliver gas previously loaned by Nicor • Day(s) on which shipper wishes to take delivery of gas previously parked on Nicor’s system or take delivery of gas being loaned by Nicor • Delivery and receipt points for each transaction • Quantities of gas to be parked, loaned, or redelivered on each day
5.3.6. Risk Management Service
As system operator, Nicor does not provide risk management services. Nicor Gas’ wholesale gas marketing affiliate, Nicor Enerchange Trading, offers services that relate to reducing the risk of price changes to gas buyers and sellers (such as futures, options, and exchange of futures for physicals).
8 The MDCQ is the Maximum Daily Contracted Quantity. It is computed as the greater of the highest daily use from the previous year or the peak day (determined through regression analysis) from the previous year’s winter. The MDCQ is subject to Nicor Gas approval and is reevaluated every year.
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5.4.1. Information Services
Nicor Gas has established a number of electronic-based tools that both facilitate customer transactions and disseminate information.
Gas Exchange
This is a web-based site that allows customers to electronically schedule and nominate service as well as trade and transfer gas and capacity.
The Gas Exchange Bulletin Board
This is an electronic information service that provides details on:
• General information about Nicor • Critical day information • Gas advisories • Firm pipeline capacity • Curtailment notices
Open Access Informational Database
This is an electronic information service that includes the following:
• Transportation Customer Information Database (TCIDB): This password-protected web site allows customers to access statement and billing information of current and perspective customer’s (with written customer authorization). o Customers’ contract and summary billing information including complete history of customer usage, utility charges by billing period, bill amounts, payments and account balances o Detailed information on billing charges and summary of usage, nominations and storage activity by billing period • Daily Balancing Status (DBS) Reports - daily usage, nomination and storage balance information • Electronic Billing (E-Bill) Reports - detailed billing information that appears on paper bills
Gas Transportation Customer Service
This is an electronic information service that provides details on:
• Rates and service options • Transportation contract forms • Contact phone numbers • Gas transportation supplier list
(QHUJ\,QWHUQDWLRQDO,QF 21 %59 5.4.2. Transactional Services
Nicor accommodates title transfers for gas on the Chicago Hub and handles the necessary paperwork to account for such ownership changes occurring while gas is being transported/wheeled and/or stored for shippers. Title may transfer several times for some gas before it leaves the center. In other cases, the service is simply an accounting or documentation of title transfers that may be done electronically, by hard copy, or both.
Nicor Gas also assists shippers with the administrative aspects of gas transfers, such as nominations and confirmations.
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Transco owns, operates and physically maintains the virtually whole of the UK transmission and gas distribution system. There are Independent Public Gas Transporters (IPGTs) who own operate and maintain generally, either specific point to point pipe lines or small infill networks but this represents a very small proportion of the UK gas network.
The UK gas industry was nationalized in 1948 and the British Gas Corporation was established in 1973. In April 1986 British Gas was incorporated as a public limited company and in December 1986 the UK Government sold, substantially all its shareholdings in British Gas to the public.
Since the privatization of British Gas in 1986, the physical infrastructure in the UK, which provides for the safe and efficient transport of gas from the beach terminals to the consumer has seen steady development. However the same is not true in the way in which the whole gas industry is managed and operated. There has been a radical change in the monopoly position of British Gas, the gas market has been opened up to competition and a whole new gas trading market has been established. At first, following privatization, the rate of change was relatively slow, but since 1990, the changes have been increasing more frequent and more fundamental.
The Gas Act of 1986 made provision for competition in the large industrial and commercial gas market through the duty placed on British Gas to publish a schedule of prices and by the opening up of the transmission system to use by suppliers of gas other than British Gas. The subsequent Gas Act of 1995 introduced a new regulatory and legislative framework for the onshore gas industry and paved the way for competition in the domestic gas market. The fundamental change at this time was the setting up of a new licensing system.
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The history of the British gas industry from the days of the British Gas Corporation to the present day is long and complex – a detailed chronology has been included as an appendix.
With effect from 17 February 1997, Centrica plc demerged from British Gas plc which changed its name to BG plc. Following the Centrica demerger, BG plc retained the gas transportation and storage businesses, the majority of the exploration and production business, the international downstream business, the research and technology business and the property division of British Gas plc.
In connection with the Centrica demerger, British Gas plc’s gas sales, services and retail businesses, together with the gas production business of the North and South Morecambe gas fields and its direct interest in Accord Energy Limited were transferred to Centrica plc. With effect from 1 May 1999, BG plc combined its exploration and production and international downstream businesses, which are principally engaged in gas and oil exploration and production and the integrated development and supply of gas markets.
With effect from 13 December 1999, BG was restructured so that a newly incorporated company, BG Group plc, became the new parent company of BG plc indirectly holding the Transco business in a separate sub-group, with BG Transco plc being ring-fenced for regulatory purposes from the sub-group containing the other BG businesses.
The restructuring was accompanied by a refinancing under which BG Transco Holdings plc (now Transco Holdings plc) issued approximately US $2.3X109 of bonds which were transferred together with new shares in BG Group plc to BG plc shareholders in exchange for their existing shares in BG plc. The UK Secretary of State for Trade and Industry held a special rights redeemable preference share in BG Group plc. BG plc was then renamed BG Transco plc.
Transco plc is a company incorporated in England and Wales on 1 April 1986 under the Companies Act of 1985.
On 16 October 2000, BG Group’s Shareholders approved the demerger of certain businesses (principally Transco) to Lattice plc, effective on 23 October 2000. This demerger created a new listed company, Lattice plc, whose principal business, Transco plc, owns, operates and develops the substantial majority of the gas transportation system and all of the LNG storage facilities in Great Britain.
On 22 April 2002, the directors of National Grid and Lattice announced that they had unanimously agreed the terms of a recommended merger of equals to create a leading international energy delivery company. Upon completion of the merger, National Grid, which is the holding company of the merged Group, was renamed National Grid Transco. Prior to the merger Lattice was the ultimate holding company of Transco, the owner operator and developer of the substantial majority of Britain's natural gas transportation system.
The terms of the merger were based on the relative equity market capitalisations of the two companies in the period immediately preceding the announcement of the merger. The merger was implemented by way of a scheme of arrangement between Lattice and its shareholders under section 425 of the Companies Act and completed on 21 October 2002.
There were many similarities between National Grid and Transco. Both companies were system operators, both owned significant assets, both had been or were active in telecommunications, their main operating bases were closely located in Solihull (Transco) and Coventry (National Grid) around 25KM apart.
(QHUJ\,QWHUQDWLRQDO,QF 24 %59 National Grid has performed well in terms of return to shareholder. Its telecom company was started, grew well and was floated off successfully before the telecoms ‘crash’. National Grid has been aggressive in expanding in the USA.
Significant projected operating savings were identified by merging the two organisations. A major reorganisation is currently underway including closing both operating bases and moving to a new location.
The combined National Grid – Transco group is less subject to takeover by predator companies by virtue of its larger market capitalisation.
The combined balance sheet strength of National Grid and Transco should enable them to expand by acquisition more aggressively.
6.2.1. The UK Experience
Prior to the introduction of the Over The Counter Market (OCM), Transco operated a flexibility mechanism whereby shippers bid to buy or offered to sell gas to Transco for balancing purposes. The system was robust in operation, but lacked many of the features and advantages of a traded market. In particular, participants were only able to trade with a single counter-party (i.e. Transco) and were unable to trade with other shippers for balancing purposes.
These features of the flexibility mechanism resulted in a number of problems. In particular, the flexibility mechanism was seen as:
• Relatively illiquid with bid-offer spreads typically greater than those witnessed in competitive exchange based markets. This often led to cash-out prices that were not reflective of underlying market conditions but of individual company bidding strategies.
• A mechanism where Transco, as the sole counter-party, was often a distressed buyer / seller and benefited from little competitive re-pricing.
• Only open to shippers that could ensure a physical change to their gas flows during the day.
• Excluding shipper to shipper trades for balancing purposes.
These features of the flexibility mechanism contributed to the exposure of industry participants to higher costs than necessary on a number of occasions, most notably an incident on 16th and 17th December 1997, which provides a good example of the difficulties in the old mechanism. On the 16 December 1997 the so called the 'dual action effect' occurred, whereby Transco accepted System Buy bids when the system was back in balance or already over supplied with gas. It arose because of the discrepancy between changing demand forecast information used by Transco, and the restrictions placed on shippers regarding adjustments they could make to their nominations to reflect this. This specific example resulted in balancing costs of £8m, and a knock-on impact on the spot market, that was estimated by Ofgas to cost shippers an additional £4m.
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Within the framework of its network code, Transco had powers to maintain an overall physical system balance. Individually, however, each shipper was responsible for controlling how much gas it input into the pipeline system and monitoring its customers’ off takes. If there was a difference in aggregate, between the inputs and off takes made by shippers, it may have been necessary for Transco to correct the physical imbalance.
(QHUJ\,QWHUQDWLRQDO,QF 25 %59 For the system to be physically in balance, inputs and offtakes must match to the extent that any differences can be accommodated by variations in line-pack.
A target linepack volume is set which varies from day to day depending on demand and other operational requirements (such as temperature changes). A bandwidth is defined around this target, also varying with operational requirements. The balancing actions that Transco took via flexibility mechanism buys and sells, were based on the forecast of line pack at the end of the gas day, compared to these target and bandwidth volumes.
Linepack will change during the day. Transco makes its balancing decisions based on forecasts of the volumes of gas delivered to, and taken off, the system during the course of each gas day. Transco uses its own total system demand forecast, together with offtake nominations, to estimate offtakes. For its forecast of deliveries it has two primary sources. These are nominations from shippers on AT-Link, and estimates from terminal operators known as Daily Flow Notifications (DFNs). (There were no commercial incentives on Transco to minimise balancing costs.
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Before the gas day, each shipper was required under the network code to inform Transco how much gas it would input to the pipeline system, and how much its customers would off take via AT- Link. Prior to the gas day, there was no requirement that inputs and off takes should match, although, under Standard Condition 2.3 of the Gas Shipper’s Licence, there was a requirement not to act in a manner likely to give a false impression to the PGT as to the amount of inputs or off takes of gas from its system. Renominations could be made at certain periods throughout the course of the gas day although the net difference between input and off take nominations could not be changed.
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Any shipper could place a bid on the flexibility mechanism, either to provide gas to the system (a System Buy bid), or to take gas off the system (a System Sell bid). Bids were specific to a certain gas day, and could be placed or withdrawn at any time, but could not be changed once posted. If Transco took a balancing action, it would accept bids in price order (lowest price bids for a System Buy, and highest price bids for a System Sell) to fill its volume requirement. If a shipper had a bid accepted, it would receive the bid price for the gas. Delivery of the bids was expected to take place by the end of the gas day. Because of the lack of real time data, bids that were not delivered could not always be identified, particularly if the volume was small. There was no direct penalty for failing to honour the flexibility bid, and payment for the bid was received regardless. Failure to deliver simply added to a shipper’s imbalance position, and could also lead to scheduling charges. As well as price and volume, bids had to specify the entry or exit point at which they were to be delivered, the flow rate and a lead-time. Sources for flexibility bids included varying deliveries at terminals, injections or withdrawals from storage facilities, and interruption of customers.
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Shippers had a commercial incentive to balance their portfolios since any imbalances were exposed to cash-out prices.
Shippers’ daily net imbalances were bought or sold by Transco at prices determined from bids accepted through the flexibility mechanism. For a day on which a balancing action had been taken, the System Average Price (SAP) was calculated as the volume weighted average price of all accepted bids (excluding bids selected to address locational constraints). SAP was charged for imbalances within a tolerance level defined as a percentage of throughput, and varied for each shipper depending on the make up of the shipper’s customer portfolio. (On average balancing tolerances equate to around 4% of a shipper’s throughput.) If a System Buy action had been taken, then a shipper that has under- (QHUJ\,QWHUQDWLRQDO,QF 26 %59 delivered would pay a higher price, the System Marginal Buy Price (SMP Buy) which was the price of the highest System Buy bid selected on-the-day, for any part of its imbalance outside the tolerance level. Similarly, if a System Sell action had been taken, a shipper that had over-delivered would be paid the lower System Marginal Sell Price (SMP Sell), the price of the lowest System Sell bid selected on-the-day, for any imbalance outside of its tolerance.
If no System Buy bid or System Sell bid was selected on a day, the corresponding SMP Buy and SMP Sell prices were set equal to SAP. On days when no balancing action is taken, SAP (and hence SMP Buy and SMP Sell) were set to the average of the SAP on each of the previous 7 days.
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If actual inputs or offtakes differed from final nominations, a shipper might have to pay a ‘scheduling’ charge if this difference was greater than the amount of their scheduling tolerance (a deadband within which shippers were not exposed to scheduling charges). The scheduling charge was calculated as a small percentage of the SAP on each day, and hence was generally very low. (For example, entry scheduling charges during November 1998 averaged less than 0.007p/therm.)
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Under the old flexibility mechanism, the costs incurred by Transco in its balancing and system operator roles were channeled into neutrality charges. Neutrality charges comprised three separate sources of costs and revenues: • Flexibility gas – purchases and sales of gas by Transco to meet requirements for both national supply/demand matching, and locational needs;
• Imbalance gas – purchases and sales of shipper imbalances by Transco through the cash-out mechanism;
• Scheduling charges – payments made by shippers when nominated flows were different from allocated flows at entry and exit points.
The table below shows neutrality costs for a full gas year, 1 October 1997 to 31 March 1998 and for the period 1 October 1998 to 31 December 1998.
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1 October 1997-31 March 1998 1 October 1998 - 31 December 1998
Flexibility gas £15.8m £0.7m
Imbalance gas £4.0m £12.8m
Scheduling (£2.0m) (£1.3m)
Balancing cost £17.8m £12.2m
(QHUJ\,QWHUQDWLRQDO,QF 27 %59 Of these three components, the costs of imbalance gas and revenues associated with scheduling may be viewed as largely outside the direct control of Transco, although Transco’s actions in the flexibility mechanism would determine the cash-out price and hence have an influence over imbalance costs. Further, the costs of flexibility gas needed to be split into those costs associated with national supply/demand balancing and those associated with locational requirements (also referred to as constraints gas). For winter 1997/98 Transco estimated that costs associated with constraints totalled £2.1 million whilst for the period 1 October 1998 to 31 December 1998 the estimated cost amounts to £5.8 million.
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Although the flexibility mechanism had worked reasonably well and the delivery of bids had been generally good, there were several issues to be addressed. Accordingly, in March 1997, Ofgas, now Ofgem, began a two part review of the gas balancing regime. The first stage of this review comprised a detailed investigation of the operation of the daily balancing regime during the 1996/1997 winter. The second stage, covered an in depth analysis of the regime which was designed to indicate possible ways in which the balancing regime might be developed in the longer term. The first stage of the review was undertaken by Transco, Ofgas and consultants.
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The results of the review were the presented to gas shippers and other interested parties at a seminar on 7 May 1997. At this seminar a series of possible short term changes were proposed and options for longer term development were outlined. The consultants commented that it had become increasingly clear that the current regime was neither an operational balancing market nor a commodity market.
It was considered that the future of the balancing regime could involve a more formal move to create an operational balancing market or, alternatively, a fully liquid and transparent on-the-day commodity market. The point was made that an on-the-day commodity market could see the development of prices in real-time through the day, with markets being established at terminals and possibly across network constraints. For such a market to be established, the consultants thought that there would need to be considerable improvement in the information flows across the whole of the gas chain There would also be a need to encourage as broad a participation as possible in the on-the-day market. In particular, shippers, producers, traders, brokers and customers would all need to have an active role to ensure the efficiency of such a market.
Following the seminar, Ofgas published a conclusions document which presented its preferred options for short term changes and gave details of its longer term vision. In the consultation which followed, a consensus emerged for a regime based on an on the day commodity market (OCM). Following these responses, Ofgas indicated that its initial preference was to proceed with an OCM. In November 1997, Ofgas began to explore in more detail the feasibility of an OCM.
In May 1998, Ofgas published its consultation document on the development of an OCM. An industry seminar was held to discuss the document on 3 June 1998 and after this seminar, 32 written responses were received from interested parties. In addition, Ofgas held a number of meetings with small groups of shippers and individual companies to discuss the OCM.
One of Ofgas’ objectives of an OCM market was to enable the separation of Transco's supply/demand balancing, which can be undertaken at the NBP, from its role in alleviating constraints, (QHUJ\,QWHUQDWLRQDO,QF 28 %59 which requires locational specific actions. Transco had indicated its commitment to this project, and outlined a plan to achieve this objective.
Ofgas’s conclusions document proposed the establishment of Workgroups to review each of the key issues. These were to include nominations and information, cash-out, Transco incentives, and balancing tools for supply/demand balancing and constraints. These Workgroups would report their findings by the end 1998. Resulting network code modifications would be drawn up early in 1999, for implementation before the summer. Other groups were to focus on issues associated with the introduction of the market operator, including the appropriate form of governance and regulation.
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EnMO is a joint venture company between National Grid and Altra, the new company being part of National Grid Holdings (NGH). It was created specifically to operate the OCM. EnMO has personnel seconded from ESIS Ltd, a subsidiary of National Grid, and Altra, with newly recruited employees and with arms-length out-sourcing contracts with ESIS and Altra.
The OCM is a 24-hour, screen based, anonymous market operated by the independent market operator, EnMO, that allows participants to trade gas in three different markets. It is fully cleared, thus mitigating the risk of counterparty default. The OCM allows shippers’ to fine tune their within-day gas positions to ensure that they balance their off-takes with inputs at the end of the gas day. The OCM also allows Transco to buy and sell gas to ensure the residual balance of the transportation system. Three products are traded on the OCM (these are considered in more detail below:
• Title gas - the title market allows participants to trade gas at the National Balancing Point (NBP) a notional balancing point for the purposes of trading title to gas. Completion of an NBP trade may or may not lead to more gas being brought onto the National Transmission System(NTS) by a counterparty to the trade.
• Physical gas - the physical market is designed to allow Transco to purchase gas from any point on the system for immediate physical delivery.
• Locational gas - the locational market is designed to allow Transco to purchase gas at a specific location, to address local transmission constraints.
Following the introduction of the new arrangements, trading on the OCM sets the cash-out prices that are used to provide commercial incentives for shippers to balance their own intakes and off takes by the end of the gas day.
The cash-out price is the price charged to any shipper whose inputs and offtakes are out of balance at the end of the gas day. The weighted average price of all trades on the OCM sets System Average Price (SAP), the highest priced Transco trade sets System Marginal Buy price (SMP buy) and the lowest priced Transco trade sets System Marginal Sell price (SMP sell). Shippers are cashed out at SAP for any gas imbalances (where gas inputs do not equal off-takes) within imbalance tolerances, while imbalances outside of tolerances are cashed out at either SMP buy (if the shipper is short of gas) or SMP sell (if the shipper has input too much gas). There are four types of Imbalance tolerances allocated to shippers and in aggregate they are equivalent to about 3% of system throughput.
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The OCM is designed to allow shipper to shipper and shipper to Transco trades. Each trade consists of a matched pair of bid to buy and offer to sell. The market is, however, a fully cleared market, so that whenever a market participant accepts an order on the OCM, two equal and opposite trades will occur. One trade will be between the accepting bidder and EnMO, while the other will be between the originating bidder and EnMO. In this way, EnMO assumes the risk of counterparty default that each participant would face alone if trading directly. EnMO has taken out insurance to cover the risk against counterparty default of up to £25 million.
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The National Grid Transco Board has overall responsibility for matters of corporate responsibility and has established a Committee chaired by the Deputy Chairman to ensure that these areas are reviewed in appropriate depth.
The Risk and Responsibility Committee has responsibility for reviewing the non-financial risks, strategies, policies, management, targets and performance of the Company, and where appropriate our suppliers and contractors, in the following areas:
• Occupational and public safety
• Environment
• Equality and diversity
• Human rights
• Business ethics
• Role of company in society
The Committee is chaired by the Deputy Chairman and comprises the Chief Executive Officer, the Chief Financial Officer, two Non-Executive Directors and the Group Head of Safety, Environment and Corporate Responsibility. The Committee also has two external specialist advisors on safety and environmental affairs to provide a further level of assurance that these important areas are being managed appropriately.
The Committee works closely with the Audit Committee to enable the latter to provide assurance to the Board that all risks to the Company have been thoroughly assessed and managed through sound systems of internal control. The Committee is also responsible for reviewing the extent and effectiveness of our external reporting of corporate responsibility performance and its participation in relevant external benchmarks.
In line with good standards of corporate governance, National Grid Transco has put in place a number of policies to ensure the most important issues are managed appropriately. These policies also provide further details on how elements of the Responsible Business Framework will be put into
(QHUJ\,QWHUQDWLRQDO,QF 30 %59 practice. Progress in implementing these policies will be assessed through the company’s audit programme, as well as the compliance framework established by the General Counsel.
6.3.1. Autonomy
National Grid Transco owns and operates both the gas and electricity transmission networks, together with the gas distribution network in Great Britain. As such the company operates in a highly regulated market. The effects of the merger were therefore considered by the Secretary of State who cleared the merger on 2 July 2002. Subsequently, Ofgem published a paper setting out the statutory proposals for modification to the licences of NGC and Transco and the standard licence conditions of electricity transmission licences.
Ofgem proposes to modify these licences so that they provide that:
None of NGC, Transco nor any of their affiliated or related undertakings can be involved in the purchase or sale of electricity, other than with the consent of Ofgem or, as permitted by their respective licences for system operator (SO) balancing purposes. Ofgem intends to issue consents to allow NGT to retain all of Lattice’s existing generation interests (on certain terms) and to allow for Compressed Natural Gas and Liquid Petroleum Gas to be provided to certain parties;
To prevent the transfer of information from EnMo Limited (the operator of the on-the-day commodity market in gas) to NGC and/or Transco;
To remove, where appropriate, any differences between the two companies’ financial ring- fencing provisions and to update the ring-fencing provisions for both NGC and Transco, bringing them into line with the obligations for electricity distribution licensees which were revised in October 2001.
The strong message that comes through about the benefits of the merger is that it creates a platform for growth that will allow the company to realize significant value for shareholders. In other words, the merger is a way of realizing further expansion abroad.
In the UK, the regulator, as in most cases, will have an interest in the potential exploitation of market power by the merged entity and the implications of the announced plans for long-term expansion.
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6.4.1. Geographical Service Territory
Gas is delivered to the seven reception points (called bead, terminals) by gas producers operating rigs in about 100 fields beneath the sea around the British Isles. Alter treatment, which includes checking the quality, adjusting the calorific value - it is transported through 275,000 km of iron, steel and polyethylene mains pipeline.
In Great Britain, the high pressure part of Transco’s transmission system (the National Transmission System - NTS) consists of more than 6,400 km of welded steel pipeline operating at pressures of up to 85 bar. The gas is pushed through the system using 24 strategically placed compressor stations. From over 140 off-take points, the NTS supplies gas to 40 power stations, a small number of large industrial consumers and the 12 Local Distribution Zones (LDZs) that contain pipes operating at lower pressure, which eventually supply the consumer.
(QHUJ\,QWHUQDWLRQDO,QF 31 %59 For management purposes, the 12 LDZs are within 8 Distribution Networks:
• Scotland
• North of England (North & Yorkshire)
• North West
• East of England (East Midlands & East Anglia)
• West Midlands
• Wales and the West (Wales & South West)
• South of England (South & South East)
• London
6.4.2. System Operation
The set of rules governing the transportation of gas through a gas network is the Network Code. The Gas Act 1995 made provision for the introduction of a Network Code to cover the transportation of gas. The Transco Network Code is the operating system, which Transco uses in conjunction with other parties, to transportation nearly all the gas supplied in the UK. Established in March 1996, it was created after long and detailed discussions with all parties involved in the gas industry, the main players being Transco, The Regulator, producers, shippers and suppliers. The formulation of the Network Code required costly and extensive work, especially by Transco. This is because such a complex operational and legal system was put in place in the very short time of two years.
Aims of the network code
The documentation of the Network Code defines the rights and responsibilities for all who use the Transco gas transportation system.
The principle aims of the Network code are:
• Gas transportation services should meet market requirements on a non-discriminatory basis.
• System security and safety should not be affected.
• Pricing should reflect the real costs of the services concerned.
• Robust systems are developed and maintained.
• Daily energy balancing should be operated.
• Shippers are incentivised to balance their own supply and demand
(QHUJ\,QWHUQDWLRQDO,QF 32 %59 Transco’s System Control Centre manages the flow of the gas from the beach to the end consumer. It uses telemetry to collect metered data from all the operational sites to monitor the system. The National Control Centre operates and balances the high pressure National Transmission System (NTS) while the Area Control Centres are responsible for the next level down in the gas supply network - they ensure sufficient gas is available at the right place and the right time to meet consumer needs.
To support the principal Network Code documentation, there is a series of other documents which record the agreements between the parties and which define the various operations. These are:
• 1HWZRUN &RGH )UDPHZRUN $JUHHPHQW A document signed by the shipper and Transco, which covers the main elements of operating under the Code.
• $QFLOODU\ $JUHHPHQW An agreement, which covers any particular transportation arrangements between Transco and users.
• 1HWZRUN([LW$JUHHPHQWThis is the agreement between Transco and other parties, covering the provisions for taking gas off the system.
• 1HWZRUN3ULQFLSDO'RFXPHQWThe essential part of the Network Code to which the parties have signed up to.
• 1HWZRUN &RGH 7UDQVLWLRQ 'RFXPHQW This document covers any interim arrangements agreed to prior to the introduction of the Code.
• 0RGLILFDWLRQ5XOHVThese are the set of rules, which apply when the Code requires modification.
• 8.OLQN0DQXDOThis is a series of documents, which describe the communication system (The UK Link), developed by Transco and used by Transco and the other system operators.
6.4.3. Market Parties
The major players participating in the Network Code are:
• The Regulator: Although not active in an operational sense, the independent regulator Ofgem, ensures that the Network Code and those who operate under the Code, do so in a way which satisfies the terms of the licences granted to the parties • Producers: The companies, mainly offshore, who extract the gas from the ground and pipe it to delivery operators • Delivery Facility Operators: The operators of the gas processing terminals • Public Gas Transporters (PGTs): The operators of the network which transports the gas from the terminals to the consumers • Storage Operators: Organizations operating the facilities where gas can be stored • Shippers: A company buying gas from producers, selling it to a supplier and employing the PGT to transport the gas to the consumer • Suppliers: The company having a contact with a shipper to buy gas and then selling it directly to consumers • Gas Traders: These are organizations buying and selling gas from each other before it reaches the consumer. They operate in the OCM or other markets. Some traders have entered the market in order to trade gas without acquiring a physical position
(QHUJ\,QWHUQDWLRQDO,QF 33 %59 • Market Operators: A market operator provides the mechanism for trading the gas. There are currently three electronic gas trading systems in the UK. The On-the–Day Commodity Market (OCM) is provided and operated by ENMO, whilst the International Petroleum Exchange’s NBP Natural Gas Futures contact and the broker EES’s Zuma 2000 cater for over-the-counter electronic trading
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Ofgem regulates every aspect of the UK gas market closely and in detail.
Ofgem’s responsibilities are set out in the Gas Act 1986, the Electricity Act 1989, as amended by the Utilities Act 2000 and related legislation. In fulfilling its obligations Ofgem works closely with the Department of Trade and Industry (DTI) and Energywatch, a consumer protection organization.
The management committee of Ofgem divides responsibility for the regulation of all electricity and gas regulation into three principal areas:
• Customers and supply
• Competition and Trading Arrangements
• Regulation and Financial Affairs
Notably safety is absent from this list and this is overseen by the Health and Safety Commission (HSC), which in turn reports to DTI. There is close liaison between Ofgem and HSC.
Transco is responsible for every aspect of the NTS. Ensuring that the NTS operates safely, reliably and that it enables a fully competitive gas market to operate.
Transco also has social and environmental obligations. Transco’s social responsibilities relate to the Energy Efficiency Commitment (EEC) clauses in Transco’s operating license. The EEC is developed by the Department of the Environment, Food and Rural Affairs (DEFRA) and Ofgem. The EEC relates mainly to providing services to the UK fuel poor (those whose energy bill exceeds 10% of their net income).
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6.6.1. Capacity Booking
Capacity booking enables shippers to book the transportation capacity they require from Transco. A shipper who has signed the framework agreement of the Network Code can book trade capacity.Transco is allowed by Ofgem to earn a specified level of return on its assets. The large cost of building and extending these assets relates to the capacity they provide. Transco therefore aims to raise a significant percentage of its revenue from capacity charges. Transportation capacity is booked by shippers or assigned by Transco in three places:
• At entry to the National Transmission system (NTS) from a sub-terminal or on-shore field (entry capacity),
• At the NTS off takes (exit capacity), and
• Within the Local Distribution Zone (LDZ) (QHUJ\,QWHUQDWLRQDO,QF 34 %59 A shipper is responsible for obtaining its total NTS entry capacity at a level appropriate to its aggregate customer base. Shippers obtain their entry capacity by bidding for it through a series of capacity auctions. Pricing incentives exist to encourage shippers to hold the majority of their entry capacity as monthly capacity and they obtain this in advance from auctions, which are ordinarily held every six months. Daily capacity auctions are also held which provide shippers the opportunity to bid for additional capacity to meet their needs for individual gas days. Transco may also buy back capacity rights when it is unable to transport all of the gas shippers wish to deliver.
Transco is largely responsible for booking National Transmission system (NTS) exit capacity and LDZ capacity on behalf of shippers, on a month-by-month cycle for their Daily Metered (DM) sites, and on a daily cycle for their Non Daily Metered (NDM) sites.
There are strong incentives to ensure shippers book sufficient capacity. If a shipper delivers more than its entry entitlement or off takes more than its exit entitlement at its firm DM sites, a charge, equivalent to 12 months capacity charge at a premium rate is incurred. Additionally, at entry, a tranche of capacity is booked for the shipper by Transco to offset the risk of further capacity breaches. If a shipper exceeds its LDZ capacity entitlement for firm DM sites, it incurs the 12-month charge and must also pay at the higher capacity level from then on.
6.6.2 Scheduling Service
After the finalisation of nominations, Transco decides how best to transport the nominated gas. Transco takes into account the various routes that are available and any constraints on the network (e.g. Maintenance). Scheduling evaluates the various alternatives to compare the various alternatives to compare nominations against the available capacity for the following day. If it is necessary to curtail any nominations, this is achieved by an agreed procedure, which is defined in the Network Code.
If ashipper’s actual inputs or off takes differ from its final nominations, it will pay scheduling charges if the difference is greater than its scheduling tolerance. Input scheduling charges are calculated as the difference between a shipper’s final nomination and final allocation at each entry terminal.
Absolute differences between 3% and 5% attract a charge of 2% of system average price. Absolute differences of more than 5% are charged at 5% of system average price. Off take scheduling charges are levied on a site specific basis, with different charges for different types of sites.
6.6.3. Balancing Service
The NTS has some flexibility within it to accommodate imbalances within the day. This flexibility comes from the storage capacity in the pipeline system itself known as system line pack. Under the current arrangements shippers pay Transco for line pack in a ‘bundled product’ with transmission services and Transco uses system line pack as a tool to help it balance the system.
Transco determines NTS Line pack by calculating the volume of gas within the NTS pipelines using a network model and instantaneous measurements. The model contains a database of NTS pipeline diameters and lengths, updated as required to accommodate changes to the network. The Opening NTS Line pack for a Gas Day, which is equivalent to the Closing NTS Line pack for the preceding Gas Day, will be the volume calculated by the network model as close to the start of the Gas Day as possible.
Ofgem believes that line pack should be unbundled and sold to shippers by way of a price auction. Shippers would then be able to purchase line pack and then use it to manage their inputs and (QHUJ\,QWHUQDWLRQDO,QF 35 %59 off takes from the system over the day. Shippers could over-deliver into line pack holdings early in the day and then withdraw gas from line pack later in the day to meet their nominations. Alternatively, shippers who have signed off take contracts with rates that vary during the day could nominate and deliver inputs at a constant rate and use line pack to avoid any cash-out exposure.
Ofgem has noted that a majority of respondents to its proposals for further reform of the gas trading arrangements supported the sale of line pack. However, Transco have commented that there is no evidence that, in the absence of fundamental reform of gas balancing arrangements, investment decisions are being materially distorted. Transco’s view is that, if there were such evidence, locational price signals would be required. Such signals would not be delivered by Ofgem’s proposals and could in any case only be achieved by introducing locational energy and line pack markets, thereby losing the benefits of liquid trading at the National Balancing Point. Further reform of the gas trading arrangements is subject to further review and consultation reform and no major changes are expected in the near future.
6.6.4. Capacity Trading Service
In addition to booking capacity on the National Transmission system, a shipper can buy entry or daily metered (DM) exit capacity on the secondary market from another shipper who has spare capacity. Once shippers have completed a capacity trade, the details are registered with Transco. Taking account of the trade, Transco immediately updates the relevant shipper’s capacity holding.
The Transco Network Code facilitates the following capacity trading process in the following manner:
• A shipper with spare capacity posts a ‘Capacity Offer’, specifying the quantity, location, duration, and suggested price of the capacity • A shipper who needs capacity can scan the list of outstanding offers. For each offer, it can see what capacity bids have already been received, though not who the bidders are. It can then post a bid for some or all of the capacity for some or all of the duration. The bid price may be different to that requested on the offer. Once a bid has been made, it cannot be amended but it can be withdrawn. If a bidder wishes to change any aspect of a bid, it must create a new bid • The offering shipper reviews the bids and may select one winning bid The computer system then effects the transfer of entitlement Although capacity entitlement passes to the successful bidder, liability for payment of the capacity charges to Transco remains with the original owner
Transco takes no part in the financial settlement of the trade because it is the responsibility of the parties making the trade.
Two shippers may agree to trade capacity directly i.e. without inviting and selecting bids. The selling shipper records the offer plus the name of the buying shipper. The buying shipper approves the transaction to confirm the trade.
6.6.5 Storage, Parking and Loaning Services
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In April 1998, Ofgas launched a detailed investigation into the market for gas storage and related services. This review concluded that BG Storage possessed significant market power, at least in the short term, and that it was being exercised in ways that were hindering the development of competition and harming consumers. (QHUJ\,QWHUQDWLRQDO,QF 36 %59 In September 1998, Ofgas proposed new arrangements for selling capacity at Rough and Hornsea, by auction, for the storage year 1999/2000 and for each of the four subsequent storage years. The underlying objective of the new arrangements was to promote a timely transition to a more competitive and efficient storage regime.
The proposals were implemented, after consultation, in April 2000, and the facilities are now run by a separate business unit called Transco LNG. The last two years have seen the first auctions of storage capacity following Ofgem.s reforms of the storage market. Auctions at BG Storage’s Rough and Hornsea facilities took place in March 1999 and 2000. At Transco’s five LNG sites, the first auctions took place in May 2000.
The transportation system has a number of storage facilities connected to it, and in general these are treated in the same way as other inputs and outputs.
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The major gas storage sites in Great Britain are the Rough off-shore facility, Hornsea, and the five Liquefied Natural Gas (LNG) facilities. Originally, all the facilities were owned and operated by British Gas plc. The ownership of Rough and Hornsea was then transferred to BG Storage Ltd (a ring- fenced subsidiary within the BG Group). In November 2001, Dynegy purchased BG Storage Ltd. Subsequently, this storage facility was acquired by SSE (Scottish & Southern Energy) Energy Supply Limited in September 2002.
Hornsea accounts for 3,495 GWh (328X106 M3) of storage space (approximately 9% of GB total) and 195 GWh/day of deliverability (approximately 13% of GB total). The corresponding figures for Rough are 75% of total GB storage space and nearly 30% of total GB deliverability.
Transco’s LNG sites account for around 10% (4,062 GWh) of storage space but 55% (812 GWh/day) of deliverability. The withdrawal lead times range from one to eight hours, and injection rates from twelve hours to ten days.
Depleted gas fields - gas is compressed back into the field for subsequent use. The offshore Rough facility connected to the Easington terminal is by far the largest, holding more than 29.3 GWh. Onshore fields can also be used.
LNG is operated by a ring-fenced business unit in Transco, and the terms of its services are included in the Network Code and summarized below. Other storage facilities are operated by other companies.
Uses of Storage
Storage has three main uses:
• 6XSSO\DQGGHPDQGPDWFKLQJGas production facilities are designed to vary their output rates to accommodate changes in demand. However it would be uneconomic to provide sufficient production capacity to meet high levels of demand. Storage helps shippers to achieve a better supplies to demand match, throughout the year.
• 2SHUDWLQJ0DUJLQVThe safe operation of its system by using storage (particularly LNG) to deal with operational incidents such as:
o Large changes in demand forecasts
o Sudden loss of offshore supplies
(QHUJ\,QWHUQDWLRQDO,QF 37 %59 o Compressor trips (breakdowns) and breaks in the pipeline
o Orderly run down if supplies are exhausted
This is known as Operating Margins storage and rules for its use are included in the Network Code.
• 7UDQVPLVVLRQ 6XSSRUW - Storage facilities close to areas of high gas demand increase the capacity to supply demands in those areas, avoiding unnecessary pipeline investment. Facilities that provide this service are designated as Constrained Storage Facilities in the Network Code. Transco has the right to order gas flows from these facilities when demand is high. Gas stocks in these facilities must be maintained at appropriate levels, depending on the time of year, so that gas can be made available when required. In recognition of this service, shippers booking a storage service at these facilities receive a ‘transportation credit’ from Transco. At present there are three Constrained Storage Facilities, Isle of Grain LNG, Avonmouth LNG and Dynevor Arms LNG
6.6.6. Entry capacity and gas capacity auctions
Since the privatisation of the UK gas industry, the industry has been subject to a regulatory system, which has brought about very significant changes in both the structure of the industry and the way in which it operates. A particular step in this process occurred in October 1999, when The Office of Gas Supply (OFGAS) introduced ‘The New Gas Trading Arrangements (NGTA)’.
These new gas trading arrangements were designed to provide for a more realistic reflection of the costs of balancing supply and demand in the national gas pipeline system. In particular, they also had to address the issue of supply constaints, such as those in 1998 at St. Fergus when the cost of Transco’s selling and buying gas gave rise to an estimated cost of US $14X106. A key feature of the new gas trading regime was a screen-based, on-the-day commodity market (OCM), which replaced the previous Flexibility Mechanism, which Transco, the pipeline operator, used to balance the system.
The New Gas Trading Arrangements also included changes to the way shippers bought entry capacity to the high-pressure national transmission system (NTS). Up to October 1999 Transco was obliged to sell to shippers an unlimited amount of annual capacity to enter gas into its system. This was irrespective of the amount of ‘physical’ capacity available and followed an agreement in 1994 when the principles of the Network Code were agreed. Under the NGTA, entry capacity sold by Transco became limited to that which is actually available.
The introduction of NGTA by the Office of Gas Supply was the result of two years of detailed consultation between Ofgas, Transco, and shippers. Ofgem were keen to claim the success of NGTA, particularly as theses new arrangements were seen as an important forerunner for similar arrangements for the electricity industry. However Transco and many of the shippers were not so enthusiastic. The NGTA are part of a continuing evolutionary process of regulation and there have been further developments to the gas trading regime, including improvements to the gas balancing system.
The capacity auctions have also undergone considerable change since their introduction in 1999. The most recent change being in October 2002 with the introduction of long-term capacity auctions. Before this, the entry capacity was sold through short-term auctions, which sold monthly and daily capacity rights. The introduction of long-term auctions is intended to provide the industry with more certainty and improve the market signals Transco receives to help it make efficient investment decisions. The long-term gas entry capacity auctions will start early in 2003.
It is Ofgem’s view that these changes will produce:
(QHUJ\,QWHUQDWLRQDO,QF 38 %59 • A fair and transparent method to allow shippers and producers to get their gas onto the NTS
• A chance for every shipper to compete equally and fairly for entry capacity
• An efficient way to allocate entry capacity to those shippers who value it most
• Investment signals for Transco by showing which terminal’s capacity is most in demand and would benefit from further investment to increase its capacity.
Under these new conditions, Transco will auction entry capacity at each of its terminals for up to 15 years ahead. Capacity will be released in quarterly and monthly blocks through a combination of long and short-term auctions. However, 20 per cent of the entry capacity will be reserved and only auctioned off a year ahead of use. Shippers will also be able to secure capacity on a daily basis. This allows new entrants to the market access to the NTS network.
In the long-term auctions Transco will publish prices for different levels of entry capacity available at each terminal. This will also include prices for increasing the entry capacity at each terminal by up to 50 per cent. Shippers will bid for entry capacity at these prices. Transco will use this information to inform investment plans for its system. Shippers will then be allocated entry capacity rights at a common price for each quarter at each terminal.
6.6.7 Gas compression
As the owner and operator of the National Transmission system, Transco has 21 compressor stations, with a total of 56 compressors, operating on the system.
These installations consist of centrifugal compressor units driven mainly by gas turbines; two compressors are electrically driven. Minimising compressor fuel costs is a major operational objective for the NTS.
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6.7.1. Information exchange
In order to ensure the efficient and transparent running of the transportation service offered by Transco, the following daily and/or monthly reports are issued:
Shipper Operation Reports
These reports are produced for each shipper and include, for example, balancing performance, scheduling performance, capacity booking and trading activity, nomination and re-nomination activity and accepted flexibility bids.
Network Operations Reports
These provide information about factors such as the forecast and actual demands, accepted flexibility bids, imbalance charge prices, patterns of supply at sub-terminals and the use by Transco of top-up storage, balancing margins, operating margins etc. They analyse trends over a month and from month to month.
The supporting computer system for operational contact
(QHUJ\,QWHUQDWLRQDO,QF 39 %59 The information exchange necessary to operate the Network Code involves the fast transfer of large volumes of complex data. It therefore requires a modern communication and telecommunication system to affect the interchange. Transco and its customers share a single computer system.
The applications making up the UK Link, are operated by Transco and they share a common database. Within the UK Link, AT Link manages the energy balancing, entry and exit capacity regime, giving shippers on-line access to their data.
6XSSO\SRLQW$GPLQLVWUDWLRQ - enables shippers to take responsibility for the transportation charges to each of their consumers.
,QYRLFLQJDQG5HFRQFLOLDWLRQ - calculates Transco invoices and sends them to shippers.
6LWHVDQG0HWHUV - maintain the database of the premises linked to the network, on which all the other sub-systems depend.
The physical communications infrastructure to achieve this transfer of information is called the ,QIRUPDWLRQµ;FKDQJH1HWZRUN ,;1 The IXN is a Wide Area Network (WAN) consisting of ‘gateways’ sited at Transco and the UK Link user premises. These gateways use two leased lines to provide the entry points to the WAN. The users can connect their gateway to their internal Local Area Network to provide access via PCs from a number of different locations.
To post information of general interest, the 6KLSSHU,QIRUPDWLRQ6HUYLFH 6,6) is used. This covers items such as weather reports, maintenance schedules, contacts and news. When emergency contact is required Transco transmits messages over a mobile radio network to a remote messaging device held by each shipper. This device acknowledges a successful receipt of the message, enabling Transco to make alternative contact by means of telephone or fax if necessary.
Transco has a number of extensive web sites, which provide for an exchange of information and queries between the various parties involved in the transportation of gas. Also, Transco issues a magazine with the title of ‘Focus’, specifically for Shippers.
6.7.2. Transactional Services
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Except where stated, Transco calculates the charges each day. These include:
• Capacity - for entry exit and LOZ capacity.
• Commodity - for transporting gas to the NTS exit and within theLOZ
• Customer - for costs associated with the shippers’ supply points
• Capacity overrun (monthly), flexibility overrun or supply point ratchet (monthly) - when a shipper ships more than its capacity entitlement.
• Scheduling - based on the difference between the nominated and delivered quantities.
Some transactions may result in either payments or charges:
(QHUJ\,QWHUQDWLRQDO,QF 40 %59 • An imbalance caused by supplying too much produces a payment; supplying too little creates a charge.
• Reconciliation may produce a rebate or an extra charge.
• Top Up revenues/costs lead to rebates/charges.
• Adjustments associated with the correction of erroneous data may be positive or negative.
• Late settlement of a Transco invoice generates an interest charge, late settlement of a payment by Transco generates an interest payment.
The final rule in this area is that Transco must not make or lose money from maintaining the system balance. Therefore each month items such as the total receipts and payments for accepted bids, imbalances and scheduling charges are netted out. Each shipper then receives a debit or credit in proportion to the amount of gas it shipped that month. However, Transco is incentivised to maintain the system balance at minimum cost.
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Much of the data on which these charges and payments are based (e.g. allocations and balances) is made available to shippers on the day following the gas day to which it relates. They are not necessarily the final values as there may be an agreed period to allow for revised readings, claims, etc. However, they give shippers an early indication of the likely charges/payments and allow many queries to be raised and resolved before the invoices are raised.
The generation of Transco invoices follows a monthly cycle. Separate invoices are produced for the separate elements at different times throughout the month to spread the administrative workload.
The volume of data in a typical invoice can be quite large. Invoices are therefore transmitted to shippers as electronic files via the Information ‘Xchange network. They can then load these files into their own computer systems for data manipulation or printing.
The data created by the daily cycle of processes is also used to monitor and improve performance.
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Safety is Transco's number one priority. The substantial acceleration of Transco's programme for replacing iron gas mains with high integrity polyethylene pipes has been agreed with the UK Health and Safety Executive. This will involve the replacement of some 91,000km of iron mains over the next 30 years.
Transco also operates the freephone 24-hour national gas emergency service (0800 111 999). Its three call centres between them receive in the region of 6.5 million calls each year and respond to around 1.4 million gas escape reports.
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Transco currently owns around 21 million gas meters - about 99% of all such meters in Great Britain. Its subsidiary, Transco Metering Services, provides metering and meter reading services to Transco and manages the relationship with its customers, the gas shippers. A separate Group business is being established to pursue opportunities in the competitive metering market. (QHUJ\,QWHUQDWLRQDO,QF 41 %59 6.7.3. Incentivising Transco to Provide Connections
The UK is unusual in having liberalized energy markets but a clear monopoly system operator. This situation could significantly impact on the expansion of the gas market both to new domestic housing developments and major power generation schemes. The study considered this aspect of regulation in the UK. Specifically, what incentives are there for Transco to extend the transmission and distribution system to meet the demands of, for instance remote unconnected loads or new housing developments?
Ofgem estimates that Independent Public Gas Transporters (IPGT) are gaining around 60 per cent of connections to new premises in the competitive market. Thus the market is no longer dependant on Transco.
An IPGT can establish a charging methodology that reduces the initial charge for providing a connection by recovering any remaining connection costs through transportation charges. This is a commercial decision, which provides for competition and market forces.
A gas transporter is obliged to connect premises consuming up to 2,196,000 kWh per annum that are within 23 metres of a relevant gas main on that transporter’s network.
The gas transporter will quote a price for connecting premises that are more than 23 metres from a suitable main and/or that are likely to consume above 2,196,000kWh per annum. All work to connect this type of premises is chargeable.
Customers can employ a gas engineer who is qualified to carry out gas connections work. Although some independent engineers carry out domestic connections, they tend to specialise in larger non-domestic connections. This work must be carried out in accordance with statutory gas safety regulations. If a premises will consume less than 2,196,000kWh every year, a Public Gas Transporter (PGT) automatically takes ownership of the service pipe and takes responsibility for its future maintenance and replacement.
If a premises is expected to consume above 2,196,000kWh customers have the option of retaining ownership of the pipe and arranging for its maintenance and replacement. However, most gas transporters are willing to adopt the pipe subject to it being fit for purpose.
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VENCorp – Is an independent, not for profit corporation. It is funded by energy industry participants. It does not own the network. It does have engineering capability and is responsible for both the physical and market operation of the system.
Victoria’s industrial, commercial and domestic gas customers have relied on natural gas as a dependable source of energy for over 30 years. With over 1.4 million customers, the state has one of the largest gas markets within Australia. Domestic use of natural gas - particularly for winter heating - is the highest in the country.
Victoria is served by a single natural gas transmission system. Gas supplies come primarily from the Bass Strait and smaller fields in South Western Victoria. The GasNet Australia Group (GNA) is the main owner of the transmission pipeline network that is characterized by multiple supply points and multiple off-take points. It is responsible for transporting almost all of Victoria's natural gas supplies to approximately 1.4 million households and over 40,000 commercial and industrial users. The network’s 1,935 km traverse much of the state, and has an average annual throughput in excess of 200 X 1015 joules, worth over US $280 million.
GNA Group’s pipeline network consists of:
• The Principal Transmission System (main transmission pipeline)
• The Western Transmission System
Under agreement with GNA, the Victorian Energy Networks Corporation (VENCorp) operates both systems as an Independent System Operator. VENCorp has major operational, planning and development roles for both gas and electricity. The GNA Group is responsible for the management of its transmission assets, while VENCorp undertakes the system and market operating functions.
7.1.1. History
In recent years, major reforms of the gas industry in Victoria have been paving the way to a competitive market. They include the following measures:
• The state-owned monopoly gas supply and retail corporation was disaggregated into a number of privatized entities including separate distribution and retail businesses. • A wholesale gas market was introduced, commencing operation in March 1999, with the establishment of an independent transmission system and market operator. • Market and System Operations Rules (MSO Rules) were established by the federal regulator - the Australian Competition & Consumer Commission (ACCC). They define the rights and obligations of all users of the Principal Transmission System and the wholesale gas market in Victoria. • Gas retail competition has been implemented in progressive steps, beginning in October 1999 with the largest customers being able to choose their retailers. All customers are expected to be able to choose their retailers by the second half of 2002.
(QHUJ\,QWHUQDWLRQDO,QF 43 %59 7.1.2. Corporate Structure
VENCorp’s structure can be summarized as follows:
• VENCorp is a statutory body established in March 1999 under the Victorian Gas Industry Act. • It was established as a non-profit organization funded by energy industry participants and is quarantined from any liability • The roles and responsibilities for ownership and operation have intentionally been separated. VENCorp does not own pipeline or storage facilities (and therefore has no direct financial interest in market outcomes). This ensures that operation of the pipeline system, the scheduling of market offers for gas injections and withdrawals, and the release of market and system planning information are undertaken in an open and transparent manner • VENCorp’s operation of the wholesale gas market is overseen by an independent Board made up of representatives of gas market participants • The Board has established a Gas Market Consultative Committee (GMCC) as a participant-representative forum to review the gas market design and operation and recommend changes for ongoing development of the market to meet stakeholder requirements
7.1.3. Autonomy
VENCorp oversees gas transportation for third parties in Victoria, in accordance with the government’s MSO Rules. Terms, conditions, and tariffs under which third parties may ship gas on these systems are defined in Access Arrangements9. VENCorp’s role is to ensure transparency and accountability in the operation of the transmission network and the associated wholesale gas market.
The MSO Rules also govern the procedures for operation of Victoria's gas spot market and lay out the responsibilities and duties of VENCorp and participants in that market.
It is anticipated that the MSO Rules will evolve and change over time as experience is gained and market conditions change. The VENCorp Board has established an industry-representative committee called the Gas Market Consultative Committee (GMCC), whose responsibility is to consider and make recommendations to the Board on market design issues and proposed changes to the MSO when warranted.
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7.2.1. Geographical Service Territory
VENCorp is the independent system operator of both the Principal Transmission System (PTS) and the Western Transmission System (WTS). PTS is Victoria’s primary high-pressure gas transmission system comprised of just over 1700 km of a pipeline network that transports gas between four injection points:
9 There are separate Access Arrangements for the Principal and Western Transmission Systems. (QHUJ\,QWHUQDWLRQDO,QF 44 %59 • The Longford gas processing plant in the south-east • The Otway Basin field and underground storage facility in the south-west • The interconnection with the NSW system at Culcairn, north of Albury • The Liquid Natural Gas (LNG) storage facility at Dandenong
The Western Transmission System supplies the western part of Victoria from the gas fields in the Otway Basin to Portland. It is expected that this pipeline will become part of the Principal Transmission System and be subject to the MSO Rules in 2002/03.
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7.2.2. System Operation
The Principal Transmission System has the characteristics of an interconnected network of pipelines rather than a point to point pipeline. There are multiple supply and off-take points. Each day, gas is offered into the transmission system from the various injection points, with multiple parties offering gas supplies at each of those sources. Gas flows on substantial sections of the transmission pipeline can be bi-directional, dependent on market and demand conditions.
To receive service, market participants pay a variety of charges depending upon their transactions. These include:
• VENCorp charges: These cover the cost of operating the transmission system as well as the wholesale market. They are determined on a cost-recovery basis and are regulated and reviewed annually by the ACCC. • Transmission Use of System Charges: These are charges levied by the transmission pipeline owner for use of the transmission system. • Distribution Use of System Charges: These are transportation charges levied by the distribution companies.
The breakdown of the cost components typically incurred by market participants is shown below:
(QHUJ\,QWHUQDWLRQDO,QF 45 %59 Approximate Cost of Gas for a Large Customer
According to the Victoria Gas Industry Tariff Order issued in 1998:
• VENCorp cannot charge customersmore than amounts calculated in accordance with the relevant tariff for VENCorp service permitted by the Order.
• VENCorp is allowed to recover its annual total costs on a yearly basis.
7.2.3. Market Parties
VENCorp is the system operator of a market that is comprised of the following parties:
• Producers:Parties who undertake the extraction and/or storage and processing of natural gas for injection into the pipeline system • Transmission pipeline owners:Owners and operators of gas transmission system facilities used to transport the gas between injection (e.g. production or storage facilities) and withdrawal points (e.g. another transmission pipe or storage facility) as well as to customers or the distribution networks. • Interconnected pipeline owners:Operators of other transmission pipelines that connect to the Principal Transmission System • Storage providers:Owners of facilities that store natural gas • Transmission customers:Recipients ofgas directly supplied from the transmission system, rather than the distribution system • Distributors:Owners and operators of the pipeline infrastructure that transports gas from the transmission pipeline to end-use customers. Distributors need to be licensed by the Office of the Regulator General (ORG). • Retailers: Sellers of gas to end-use customers, to and from other market participants or producers; also transporters of gas through transmission system. Retailers need to be licensed by the Office of the Regulator General (ORG). • Traders: Buyer and sellers of gas to other market participants or producers; also transporters of gas through the transmission system. Traders may not sell gas directly to end-use customers in Victoria without obtaining a retail license. • Wholesale Market Customers:Buyers of gas directly from the wholesale market for personal consumption • Retail Market Customers – End users who, with the introduction of retail contestability, choose to purchase from their retailer of choice (QHUJ\,QWHUQDWLRQDO,QF 46 %59 7.2.4. Obligations and Interdependence of Market Parties
The basic legal obligations of VENCorp and market participants are as follows:
• VENCorp must operate subject to the MSO Rules. • Parties who wish to participate in the gas market must register with VENCorp.
o Producers, pipeline owners, and storage providers are required to register with VENCorp and be subject to the MSO Rules. o Gas transporters, traders, and wholesale customers are required to register with VENCorp as Market Participants.
Before VENCorp approves a registration, prospective participants need to meet specific obligations applicable to their relevant participant category. Some of the major obligations are as follows:
• Gas Transportation Deed: Market parties must sign an agreement under which they are obliged to pay transmission charges to the pipeline owner for the use of the pipeline (charges are collected by the pipeline owner) • Distribution Use of System Agreement: Market parties must sign an agreement under which they are obliged to pay distribution charges to the pipeline owner for the use of the pipeline (charges are collected by the pipeline owner) • Prudential Requirements:A person or business intending to become market participant must provide appropriate financial securities in the form of a bank guarantee, to cover potential liabilities to the market
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7.3.1. Capacity Booking
The Principal Transmission System in Victoria currently has sufficient capacity to supply all consumers’ daily gas needs without suffering congestion on the pipeline (i.e. exceeding the daily capacity of all or part of the pipeline) for all but a few days in the year. The sequence for booking capacity is described below.
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Market participants inform VENCorp about the quantities they wish to inject and/or withdraw during the gas day. There are two ways to provide this information:
• Nominations: Market participants may submit nominations specifying the quantities of gas they wish to inject into, or withdraw from the Principal Transmission System during that day irrespective of the spot market price • Increment/Decrement (Inc/Dec) Offers: Market participants may submit price-related offers to increase or decrease their injection or withdrawal quantities at specified connection points in response to price signals. Each Inc/Dec offer may specify several prices and corresponding quantities of injections or withdrawals that the market participant is prepared to implement if the market price reaches the specified value.
(QHUJ\,QWHUQDWLRQDO,QF 47 %59 7.3.2. Scheduling Service
Under the MSO Rules, VENCorp manages pipeline capacity using the mandated Market Carriage mechanism by which gas is scheduled and the system balanced using daily price signals rather than regulation.
VENCorp’s scheduling of gas transportation can be described in the context of daily operational activities undertaken in the gas market. During the gas day, VENCorp schedules gas to meet the forecast demand. After the gas day, VENCorp sets the market price based on final demand, and market participants settle their net daily imbalances at the market price.
During the Day
Nominations or offers are made in advance for the gas day, the next gas day (i.e. gas day + 1) and the second gas day (i.e. gas day + 2). During the day, VENCorp monitors changes to system conditions and demand against forecast. VENCorp combines information on nominations, Inc/Dec offers, with information on other factors (such as current physical conditions of the transmission system and likely demand for the current and following days) to produce schedules for the daily operation of the gas system10. Nominations are scheduled by VENCorp before Inc/Dec offers and independent of market price. If necessary, VENCorp uses the participants’ nominations or offers to re- schedule gas in order to operate the Principal Transmission System and meet the changing requirements in demand.
The nominations and offers for ‘gas day + 1’ and ‘gas day + 2’ represent market participants’ reasonable intents, and the schedules provided by VENCorp for these future days are indicative only. They are intended to serve as guides to market participants on likely gas requirements for those days to allow them to make/ adjust their gas orders, and are not used to determine the spot market price or to settle the market.
$IWHUWKH'D\ • At the end of each gas day (9.00 am – 9.00 am), metering data are collected to determine the actual total system demand and daily imbalances of individual market participants, as well as usage of gas by large customers over and above their AMDQ (for allocation of uplift charges). • The daily spot market price ($/GJ of energy) is then determined and published by 4.00 pm of the following gas day. • A market participant’s net daily imbalance is settled at the daily market price for the day. • Participants whose injections are greaterthan their withdrawals (in GJs) on a day are entitled to the following wholesale market payment: ,QMHFWLRQV±:LWKGUDZDOV X0DUNHW 3ULFH • Participants whose injections are lessthan their withdrawals (in GJs) are liable for the following wholesale market payment: :LWKGUDZDOV±,QMHFWLRQV X0DUNHW3ULFH
10 These schedules include the forecast demand and forecast gas price for each day. (QHUJ\,QWHUQDWLRQDO,QF 48 %59 Source: ‘VENCorp’s Guide to the Gas Market’, Victorian Energy Networks Corporation
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Congestion and Scheduling
In the event that part of the pipeline system becomes congested it may be necessary for VENCorp to re-schedule gas supplies and/or deliveries to ensure appropriate pressures are maintained throughout the system.
The way that the Victorian gas market delivers pricing signals to gas users, and a mechanism for prioritizing access to the transmission pipeline system at times of congestion, is through the allocation and treatment of ‘authorized maximum daily quantity’ (AMDQ).
The AMDQ is a quota system that allows customers to use gas up to a specified daily amount without incurring additional charges. Prior to the opening of the spot market in March 1999, an allocation11 of AMDQ was made to the then daily-metered customers (about 700 customers in total). Customers who wish to increase their AMDQ can do so by a combination of one or more of the following options:
• Negotiate with and obtain AMDQ from another customer or participant
• Arrange for gas to be injected from another source other than Longford. These injections of gas can be used as a form of credit to offset any usage of gas above the customer’s AMDQ level
11 This initial allocation was based on historical usage or pre-existing contractual rights but (since July 2001) is transferable between customer sites, customers and market participants in accordance with procedures available via the VENCorp website.
(QHUJ\,QWHUQDWLRQDO,QF 49 %59 7.3.3. Balancing Service
Unlike all other transmission pipelines in Australia, and most around the world, the amount of line pack (gas stored in the pipeline) on the Victorian system is relatively small in comparison to the peak daily demand of gas transported through the system. The line pack stored at any time on the Principal Transmission System would only provide about half of the energy required to satisfy a peak winter day’s demand. This means that, compared to most other gas transmission systems, there is limited ability to use line pack to manage deviations from forecast supply or demand for gas from the system.
Because of this, VENCorp must manage system security more closely with gas injections or withdrawals often rescheduled within the day in order to balance the system (i.e. to match the supply of gas to demand).
However, the wholesale gas market arrangements have been developed to enable same-day gas scheduling and balancing of the pipeline system to be market-driven (i.e. price-based). The principal objective of the wholesale market is to allow the market itself to find solutions for system events, rather than to rely on directions from the system operator.
Congestion
The spot market price is determined assuming there are no constraints on the pipeline and is based on actual gas demand for the gas day.
On days when congestion occurs on the principal transmission pipeline system, customers who have exceeded their Authorized Maximum Daily Quantity (AMDQ) on the day may face additional charges (called uplift charges) for their excess or unauthorized use of the pipeline system. These uplift charges reflect the market costs incurred in managing pipeline constraints on the day.
In rare and extreme circumstances when severe congestion occurs, it may be necessary to curtail customer usage of gas to maintain safe working pressures on the principal transmission system. Those gas users without AMDQ, or exceeding their AMDQ, will be required to reduce their usage of gas ahead of authorized users.
Daily Balancing
During the gas day, VENCorp will schedule offers from market participants to inject gas as required to meet variations in gas demand. There may be times when, to meet local or short-term within-the-day requirements for gas, VENCorp will need to schedule additional injections of gas that have been offered at a price which is higher than the resulting spot market price.
In these cases, VENCorp makes requests of market participants to inject higher-priced gas into the system. In order that these parties are not put at a disadvantage in comparison to the spot market price, they are compensated through ‘Ancillary Payments’, which are funded by uplift charges.
7.3.4. Capacity Trading
A secondary market for gas trading has not been developed in the Victorian system.
(QHUJ\,QWHUQDWLRQDO,QF 50 %59 7.3.5. Parking and Storage Services
VENCorp does not provide any services related to the storage of gas. Gas storage facilities are available at two injection points into the transmission system administered by VENCorp. They are: • The Otway Basin field and underground storage facility in the south-west • The Liquid Natural Gas (LNG) storage facility at Dandenong
7.3.6. Risk Management Service
Risk management instruments have so far failed to develop in the Victorian gas market to any significant extent. This can be primarily attributed to the fact that market conditions to date have presented few events that give rise to the causes of market risk. As a result, VENCorp has not facilitated the development of risk management in the Victorian gas market.
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7.4.1. Information Service
A wide range of market information is provided by VENCorp to market participants and the public on such topics as market forecasts, spot market price, participant offers and market outcomes. • Participant Information: Market information such as operating schedules, forecast prices, system wide notices advising of changing conditions / reschedules, settlement statements and relevant supporting data are published electronically on VENCorp’s Market Information Bulletin Board (MIBB), which can be accessed by participants. This system provides convenient access to the large volumes of information while ensuring that each participant can only access information to which they are entitled. • Annual Gas Planning Report: VENCorp publishes an annual gas planning review containing forecasts of gas supply and demand, as well as transmission system capability for the next five years. These reports and other data are available from the VENCorp website. • Public Information: The intention is that the wholesale market processes be as transparent as possible, while at the same time satisfying commercial confidentiality requirements. To this end, VENCorp makes available to the public a wide range of market information via the VENCorp website (ZZZYHQFRUSFRPDX). This information includes preliminary and final operating schedules (totals), forecast and actual wholesale spot market price, aggregate gas withdrawals and injections. Quantities and prices of offers are also published the following day on the VENCorp website.
7.4.2. Transactional Services
VENCorp conducts contracting, invoicing and other administrative tasks associated with non- physical movement of gas:
• On any given day a market participant may be a net buyer or seller of gas from the market. Depending on how they have been trading through the month, market participants may be out of balance, either as a net buyer or a net seller, at the end of the month. • Monies owed to and by market participants are settled at the end of each calendar month. At this time, VENCorp settles the wholesale market and invoices each market participant for their spot market trades of gas, as well as any other fees owing (e.g. meter fees, registration fees, etc).
(QHUJ\,QWHUQDWLRQDO,QF 51 %59 &203$5$7,9($1$/<6,62)6<67(023(5$7256
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*URXS See Below US $12X109 See below WXUQRYHU (Year to 31/03/02) *URXS In 2001, US $143.7X106 US $2.8 X109 See below RSHUDWLQJ Alliance net income for (Year to SURILW returned US 2001 31/03/02) $74X106 to its (91% of owners operating income comes from gas distribution) 1RRI 3,400 31,000 90 HPSOR\HHV /HQJWKRIKLJK 6,560km 1,700 km SUHVVXUH SLSHOLQHV /HQJWKRIORFDO 268,600km WUDQVPLVVLRQ GLVWULEXWLRQ SLSHOLQHV 7RWDOSLSHOLQH 1,429 km 44,800km of gas 1,935 km OHQJWK distribution system &RPSUHVVRU 724 VWDWLRQV &DSDFLW\ 37.5 X 106 cubic meters per day firm plus extra interruptible RI 2.5% More than 40% FRQVXPSWLRQLQ FRXQWU\ *DVXVHUV 5.62 million More than 21 1.4 X 106 customers in million households 640 Illinois more than communities 40,000 commercial and industrial users
(QHUJ\,QWHUQDWLRQDO,QF 52 %59 5HYHQXH (DUQLQJV>Definitions@ (QHUJ\,QWHUQDWLRQDO,QF 53 %59 Revenue (LTM) (millions) $1,769
Income from Continuing Operations (LTM) (millions) $131
Income from Total Operations (LTM) (millions) $131
Diluted EPS from Continuing Operations (LTM) $2.95
Diluted EPS from Total Operations (LTM) $2.94
'LYLGHQGV>Definitions@
Ex-Dividend Date 27-Dec-2002
Dividend Rate $1.84
Yield 5.3%
Yield – 5 Year Average 3.9%
5DWLRV>Definitions@
Price to Earnings 11.7
5 Fiscal Year High P/E N/A
5 Fiscal Year Low P/E 9.4
Price to Revenue 0.61
Price to Cash Flow 5.3 (QHUJ\,QWHUQDWLRQDO,QF 54 %59 Price to Book 2.10
Debt to Equity Ratio 0.99
Current Ratio 0.6
ROE from Total Operations N/A
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5-Year Annual Earnings Growth Rate 3.49%
5-Year Annual Dividend Growth Rate 5.92%
5-Year Annual Revenue Growth Rate 6.57%
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The Alliance Pipeline System is owned by affiliates of the following companies:
• Enbridge Inc.
• Fort Chicago Energy Partners, L.P.
• El Paso Corp.
• Duke Energy Corp.
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Nicor Inc. is a holding company. The company’s primary businesses are Nicor Gas, one of the nation’s largest gas utilities, and Tropical Shipping, a containerized shipping business. Nicor also owns several energy-related subsidiaries and is a partner in Nicor Energy, a provider of unregulated energy products and services
(QHUJ\,QWHUQDWLRQDO,QF 55 %59 1DWLRQDO*ULG7UDQVFR 8.
Although there are other Public Gas transporters in the UK, Transco as the owner of the original British Gas Corporation’s gas network, has a virtual monopoly on gas transportation. Transco, originally part of the Lattice group is now merged with the National Grid and has become National Grid Transco. This large group now controls both the gas transportation and electricity transmissions systems.
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The Victorian Energy Networks Corporation (VENCorp) is responsible for the operation of the Victorian gas transmission network and the development, implementation and operation of the Victorian gas ‘spot’ market. VENCorp is wholly owned by the Government of Victoria and is responsible to the Minister for Energy and Resources. VENCorp is totally funded by the industries it serves.
The corporation receives revenue determined under two Victorian State Government tariff orders. Through the Australian Competition and Consumer Commission, the Victorian Electricity Supply Industry Tariff regulates the transmission network and the Victorian Gas Industry Tariff regulates the gas market revenues.
The Statutory gas segment finances are:
• Expenses of US $2.18X106 (US $2.02X106 2000/01), which were 22.5% below budget.
• Gas revenue was US $560X103 below budget, reflecting a mild winter.
• VENCorp costs in this segment of US $8.06X106 (US $8,28X106 2000/01) were 9.5% below budget.
VENCorp’s surplus recognizes the variation from full cost recovery related to operating the statutory gas services. The corporation, in accordance with the Victorian Gas Supply Industry Tariff Order, Includes this surplus to determine its charges on a full cost recovery but not for profit basis as approved by the Australian Competition and Consumer Commission.
• The statutory gas segment surplus for 2001/02 of US $473,000 includes the following items:
• the planned deficiency of US $338,000 was to reduce the accumulated surplus brought forward;
• the widespread cost savings were US $814,000.
The corporation has applied this statutory gas segment’s accumulated surplus to reducing the commodity tariff by 4%, commencing 1 July 2002.
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The four system operators in this study have a common purpose – to establish an operating environment conducive to the workings of a truly competitive gas market. To date, they appear to have functioned effectively in their respective roles, although circumstances in the Victorian gas market are still evolving due to its short history pursuant to market reform. These system operators have different
(QHUJ\,QWHUQDWLRQDO,QF 56 %59 corporate structures and operate in dissimilar market frameworks. Basically, they can be classified as being one of two kinds of corporate entities:
• Joint owner/system operators (Alliance Pipeline - US and Transco - UK)
• Independent system operators - separate operators of pipeline facilities that are owned and maintained by others (Nicor Gas - US and VENCorp - Australia)
These corporate and structural differences embodied in these four case studies are discussed and analyzed below.
The job of the system operator is to ensure stability of the transmission system in order that the physical gas commodity may be efficiently transported from the producers to the distributors. In a deregulated environment, the operator maintains open access to the transmission system and provides major services such as gas balancing, congestion management, and gas flow scheduling. In addition, operators generally perform ancillary services such as metering, accounting, settlement, and billing. In countries that have instituted gas industry regulatory reform, a question often debated by industry experts regarding who might constitute the ‘best’ choice for a system operator – and independent transmission system operator or a pipeline owner/system operator. There have been proponents and opponents on both sides.
Arguments against owner/system operators are as follows:
• Owner/system operators will favor their own commercial interests over the interests of market participants. Faced with an operating or congestion problem, the operator will most likely choose a solution centered on their transmission assets, even if there are less costly alternatives available
• It is difficult to design incentives to induce the operator to minimize total transmission costs instead of just congestion costs
Arguments against independent system operators are as follows:
• Independent system operators are inherently inefficient because they are usually nonprofit organizations requiring complex systems of governance.
• It is difficult to draft and enforce contracts that will ensure that an independent system operator will efficiently and reliably operate transmission assets owned by others.
As evidenced by the cases examined in this study, both types of system operators can be made to work. It becomes evident that regardless of type, the key element for the success of a transmission system operator is true independence from ownership and control by market participants. To achieve a transparent competitive wholesale gas market, a transmission system operator, whether it is a joint owner-operator or an independent system operator, must act as an impartial party who does not favor one party over another. Impartiality is critical not only for ensuring a level playing field for all market participants, but also to instill confidence among private investors in the integrity of the industry’s operations. Some factors that are important in ensuring an impartial role for the system operator are discussed below.
8.3.1. Ownership Issues
• Two-way ownership restrictions must apply:
(QHUJ\,QWHUQDWLRQDO,QF 57 %59 • Market participants must be prohibited from having equity interests in the system operator
• The system operator (including its directors, managers, and employees) cannot have financial interests in market participants
8.3.2. Control Issues
Control can be achieved even without ownership if market participants can direct the system operator’s decision-making process. Independent system operators are generally established as nonprofit or cooperative organizations. In such cases, close attention must be paid to its governance - what decisions are made, who makes them, how decisions are enforced, and how disputes are resolved. The key to governance lies in the composition and voting rules of the operator’s governing board. An operator’s governing board can consist of stakeholders, non-stakeholders, or a combination of the two. Independent experts can be charged with the mandate of: • Assessing the performance of the system operator, the market, and the regulators • Recommending changes in structure as well as in rules
8.3.3. Market Framework
• Hubs reduce transaction costs involved in moving gas from the wellhead to the customers and make it easier for buyers and sellers to do business with one another. • They promote competition for natural gas as a commodity and in gas transportation markets. • They increase service reliability by permitting adjustments in response to emergencies such as supply area disruptions, sudden surges in demand, and pipeline capacity outages. • They introduced greater flexibility in a secondary market for shippers to release unwanted primary capacity, improving their ability to balance load and reducing transactions costs. Gas trading is facilitated through the creation of vital instruments including:
• Standard contracts that allow traders to conduct trades based on clearly defined terms and conditions. Without standard contracts, trading would require complex negotiations and documentation to ensure all terms and conditions are agreed upon. • Electronic trading infrastructure
8.3.4. Hub advantages
• Gas suppliers can wheel gas for delivery to more markets, and marketers can have more suppliers to choose from • Storage, parking, and loaning gas services offered at a hub help shippers avoid pipeline imbalance penalties • Hub services typically include a large variety of options (e.g. short-term interruptible storage, flexible injection and withdrawal schedules, and inter-month agreements) that allow customers to manage resources more effectively by taking advantage of different market and transportation opportunities • Hubs that offer gas loans can help customers take advantage of market situations e.g. when market conditions are favorable customers can make a sale with ‘loaned’ gas and repay it at a later date.
(QHUJ\,QWHUQDWLRQDO,QF 58 %59 8.3.5. Competition
The emergence of gas-to-gas competition based on the introduction of third-party access causes fundamental changes in the gas market. In North America and Britain, this process has involved:
• A diversification of the range of services available to wholesale and retail buyers
• A huge increase in the number and complexity of transactions, with all players investing heavily in sophisticated information and communication systems
• The emergence of financial risk-management instruments including futures contracts
• A shift from long-term to short-term (spot and futures) contracts for transportation and related services and for the supply of gas itself
• A move towards the use of spot gas and futures prices in the price indexation formulae in mid- and long-term supply contracts
8.3.6. Gas trading
The unbundling of gas commodity supply from transportation and related services and the removal of price controls has revolutionized the way gas is traded. Although North American and British experiences differ in some respects, the following key elements are increasingly common to both markets:
6KRUWHUWHUP DQG VPDOOHU FRQWUDFWV There has been a pronounced shift towards shorter- term contracts, notably fixed-price spot deals of one-day to one-year duration, and a corresponding decline in the use of long-term contracts. The average size of individual contracts has diminished as buyers seek greater flexibility in balancing load on a daily and seasonal basis. Local distributors and marketers in the United States and marketers in Britain generally seek a balance between short- and mid-term supplies.
'HFOLQHLQWDNHRUSD\FRPPLWPHQWV The move to short-term spot trading has resulted in a decline in the use of take-or-pay commitments in medium- and long-term contracts. This has been most marked in North America, where pipeline companies encountered severe financial difficulties in the mid-1980s as a result of onerous commitments to lift gas at above market prices under long-term contracts with producers
(PHUJHQFH RI VSRW DQG IXWXUHV PDUNHWV: Spot markets - informal markets for over-the- counter trades of fixed volumes of gas at a negotiated market price - are a central feature of the North American and British markets. Futures markets are also increasing in importance, both as risk- management instruments and a means of buying and selling physical volumes. As much as a third of the North American market and close to a fifth of the British market is supplied with physical gas traded on the spot or futures market. Total trading volumes are considerably larger, as contracts are traded many times over. Spot trading has tended to become focussed on market hubs, facilitating the coordination of short-term gas purchasing and the booking of transportation and storage services.
6SRW DQG IXWXUHVSULFH LQGH[DWLRQ The importance of spot and futures markets in gas pricing is greater than the size of those markets would suggest because of the widespread use of movements in spot/futures gas prices to index or escalate the base price in mid- and long-term contracts. In line with the oil market, almost all such contracts in the United States are indexed on spot
(QHUJ\,QWHUQDWLRQDO,QF 59 %59 or futures prices. In Britain, spot or futures gas-price indexation has only recently emerged in mid- and long-term beach contracts but is expected to become more common.
(QHUJ\,QWHUQDWLRQDO,QF 60 %59 6XPPDU\WDEOHIRUJDVWUDGLQJDQGEDODQFLQJ±86$DQG8. United States United Kingdom Primary Spot trading of FERC’s restructuring Order 636 The Network Code Gas gas and (1992) promoted establishment of introduced the concept of a Market provision of market centres (physical pipeline National Balancing Point - a transportation hubs) as basis for primary and notional point in Transco’s and storage secondary gas markets system - to give shippers services. greater flexibility in determining delivery points and facilitate trading of gas already in the National Transmission System. Auction-based system permits access to the limited capacity of the Transco network. Increasingly active day-ahead and within-day spot gas trading is supplemented by a fairly rigid set of Network Code rules involving a flexibility mechanism and Top-Up Manager, both run by Transco, which can result in punitive charges for shippers found to be out of balance on peak days. Secondary Electronic ‘on- • Released capacity rates capped at • No cap on released Gas the-day’ trading regulated levels capacity rates. Trading allows shippers • Grey market exists – holders of • Trading still relatively Market to release unused capacity capture full market value modest. transportation by bundling released capacity with and storage other gas services capacity to • Very active market balance physical positions and avoid imbalance charges.
System Maintaining Balancing largely market-driven, Balancing performed by SO Balancing close daily achieved through: on daily and several-times- balance between • Active trading of gas, a-day basis. Needed gas inputs and transportation and storage services because of: offtakes to • Pipeline Operational Flow Orders • Lack of storage ensure system requiring shippers to inject/ • Geographical safety; severe withdraw gas at short notice in compactness of pipeline financial emergencies network (limiting penalties for ability to linepack12) imbalances
12 The storage of gas within the transmission system by increasing compression (QHUJ\,QWHUQDWLRQDO,QF 61 %59 8.3.7. Contractual Arrangements
The unbundling of gas commodity supply from transportation and related services and the removal of price controls revolutionizes the way gas is traded, including the mechanisms used to price gas in contracts. Unbundling shifts the responsibility for booking transportation capacity and storage space to intermediate and/or end-use customers. These include local distribution companies (LDCs), large end users, and aggregators, marketers and brokers in the US; licensed shippers in Britain include marketing companies (often affiliates of North Sea producers) and some large end users, (such as power generators). While trading and pricing of gas as a commodity have been largely deregulated, tariffs for transportation (regulated third-party access tariffs) and storage remain tightly regulated in both countries.
Some developments over recent years in contracting for transportation and storage are common to both the North American and British markets:
%RRNLQJ HQWU\ DQG H[LW FDSDFLW\ As wholesale competition has developed, flexibility in delivery and receipt points for gas supplies has emerged as an important concern.
Until recently, a significant difference between North America and Britain concerned the length of contracts for transportation and storage capacity. In Britain, the Network Code provided for annual booking of pipeline capacity. Storage is booked through annual tenders for different types of storage. Capacity in North America has traditionally been reserved under very long term contracts, often for 20 years of more. This appears to be changing with increasing pressure from shippers (mainly LDCs) to reduce the length of contracts to five years or less in response to greater volume and price risk as competition is extended to the retail sector.
8.3.8. Tariff Structure
In North America, pipeline companies must seek approval from the regulatory authority (FERC in the United States; the NEB in Canada) for proposed rates. These proposals must be based on estimated annual operating costs plus a reasonable return on investment (cost-of-service). Rates are approved or modified on a case-by-case basis. In most cases, pipeline rates are required to be set using a straight-fixed variable methodology, whereby charges have to be broken down into a fixed capacity (or reservation) charge and a commodity charge (according to usage). Fixed costs must be allocated to capacity charges. As a result, 90% to 95% of pipeline revenue comes from capacity charges. FERC is considering allowing pipeline companies to negotiate rates where sufficient pipeline-to-pipeline competition exists. NEB is also considering alternatives to traditional cost-of-service regulations to provide incentives for pipeline companies to reduce costs and enhance the quality of service. Some pipeline companies have already agreed to mechanisms whereby they absorb some market risk in return for the opportunity to increase returns when market conditions are favorable.
In Britain, the regulator sets a cap on the average revenue Transco is allowed to earn, similarly based on cost and what is deemed a reasonable rate of return on assets. The price cap is set for periods of five years. Annual reductions in allowable average revenue are determined by an efficiency (x) factor to provide an ongoing incentive for Transco to reduce its costs to protect its earnings.
8.3.9. Investment
While the liberalization of Britain’s primary gas market has brought considerable benefits to consumers, participants expressed the concern that the continuing drive by Ofgem to introduce new market mechanisms for entry to, and exit from, transportation infrastructure may increase the risks involved in investment in the development of new sources of gas for the British market and the (QHUJ\,QWHUQDWLRQDO,QF 62 %59 requisite infrastructure. With the timing of such investment becoming critical to the security of gas supplies in the latter half of this decade, the highest priority for consumers is arguably to establish the regulatory stability and predictability needed to provide the basis for such investment. Regulatory uncertainty surrounding the commercial arrangements for entry capacity to the National Transmission System is a prime concern in this regard.
While market mechanisms arguably provide the best way of securing the efficient utilization of existing assets, there is no confidence in their ability to provide insurance against low-probability events and supply shocks. Yet given the asymmetry of risk for consumers, additional ‘insurance’ infrastructure investment, including for example strategic storage or greater flexibility in Transco’s NTS, to accommodate sudden changes of supply patterns, could be a cost-effective way of absorbing such shocks.
([SHULHQFHVDQGHIIHFWVRIUHJXODWLRQRQV\VWHPRSHUDWRUV
8.4.1. Australia (VENCorp)
VENCorp does not own pipeline or storage facilities (and therefore has no direct financial interest in market outcomes). This ensures that operation of the pipeline system, the scheduling of market offers for gas injections and withdrawals, and the release of market and system planning information are undertaken in an open and transparent manner.
Victoria is unique in Australia in having an independent, government-owned operator of a transmission system that is owned by the private sector. Whilst VENCorp’s direct costs have been reduced and its annual budget is approved by the ACCC, there are no commercial pressures on VENCorp to minimize its costs, nor is there real incentive to devise least-cost solutions or evaluate more flexible modes of operation of the system. These factors can all contribute to a level of costs that are not necessarily commensurate with the benefits provided to end-users.
VENCorp as the system operator appears to have benefited from the fact that the gas transmission reforms have been relatively recent and that the Australian Government seems to have been taken into account some of the problems experienced elsewhere. The reforms to the gas transmission system have seen the expansion of pipeline infrastructure with an Australia-wide integrated gas network as the ultimate vision. Nevertheless the gas transmission sector is likely to remain highly concentrated and future pipeline investment is likely to be driven by an increase in demand for gas, as is the case with VENCorp. The ACCC sees a growing trend to more efficient gas pricing and substantial new investment in all parts of the energy market.
There have been some concerns at the reach of regulation in the pipeline sector. However these decisions were made up front by the governments, which identified the pipelines, to be regulated. For new pipelines the regulatory framework covering gas transmission infrastructure in Australia requires that a number of tests must be satisfied before a pipeline, or prospective pipeline is regulated.
The incentive-based regulatory framework adopted in Australia attempts to overcome the weaknesses of the rate-of-return regulatory approach found in the US. Incentive regulation gives discretion to the service provider to operate its business and allows it to benefit from returns greater than those anticipated by the regulator. One of the most frequently expressed criticisms of the regulatory framework for gas transmission concerns the impact of regulation on new investment, a point which concerns VENCorp.
Despite some criticism of the gas code, it is useful to note that it was designed to facilitate a fair degree of flexibility for service providers in formulating an access arrangement for regulatory
(QHUJ\,QWHUQDWLRQDO,QF 63 %59 consideration. The ACCC’s perception is that the gas code offers a degree of flexibility that is yet to be fully realized by the pipeline industry.
The gas code allows the regulator to consider an access arrangement period of any length. However, where the access arrangement period is greater than five years it requires the regulator to consider whether mechanisms should be included in the access arrangement to address the risk of forecasts, on which the terms of an access arrangements were based and approved, proving incorrect.
2001/02 appears to have been a successful year for VENCorp. The Company improved its relationships with its stakeholders, and seems to have had a good relationship with the State Government. In particular VENCorp participated in a range of regulatory and Government policy reviews on energy market and access issues.
VENCorp has proposed revisions to the Access Arrangement to apply for Victoria’s principal gas transmission system from 1 January 2003 and it has consulted on the terms of the Access Arrangement before finalizing its submission. Views have been sought from interested parties on the range of services to be provided by VENCorp, and on proposed modifications to the budget and market fee setting process over the 2003 – 2007 access period. The proposed revised Access Arrangement effectively maintains the current terms and conditions for access to the principal transmission system, and maintains the current range of services provided by VENCorp, with an initial 4% reduction in the commodity based market fees and an effective 10% real reduction over the 5 year access period.
The Market and System Operations Rules under which VENCorp operates were originally authorized as applying up to 1 January 2003. VENCorp has now submitted an application to the ACCC for the reauthorization of the Rules for a period of ten years from 1 January 2003.Accompanying the applications was a submission setting out the role and purpose of the MSO Rules and VENCorp’s view of the net public benefits that result. VENCorp has to balance the investment with the risks involved in forecasting for a longer period.
The gas code allows the regulator to consider an access arrangement period of any length. However, where the access arrangement period is greater than five years it requires the regulator to consider whether mechanisms should be included in the access arrangement to address the risk of forecasts, on which the terms of an access arrangements were based and approved, proving incorrect. For existing pipelines, the regulator must determine the initial capital base with regard to methodologies such as depreciated actual cost and depreciated optimized replacement cost. However in the case of new pipelines, the gas code requires that the initial capital base will be determined by the actual capital cost of the assets at the time they first enter service. In other words the regulator cannot optimize or otherwise reduce the actual capital costs incurred in building the asset. It must take as given the costs of a new asset in formulating the regulated asset base.
Concerns have been raised that the present arrangements allow for forum shopping among the different regulatory agencies and that uncertainty and complexity is created by regulators interpreting the regulatory regime differently, particularly for companies operating in more than one jurisdiction.
8.4.2. USA (Alliance Pipeline L. P. and Nicor)
In the USA, the restructuring of the gas industry has been seen as a success, despite the possibility that their rate-of-return regulatory approach might have led to a lack of incentives for the regulated business to reduce costs, and to considerable administrative burdens on businesses and the regulator. Initially, it had been predicted that the natural gas pipeline system would not be able to accommodate open access and that system reliability might falter. However, in the first eight winters since the start of regulation, the interstate pipeline system functioned reliably. There has been robust competition in the gas commodity with highly transparent spot prices and production has increased. The emergence of scores of natural gas ‘hubs,’ where many gas pipelines converge and trading was robust, also attested to the success of the open access system. (QHUJ\,QWHUQDWLRQDO,QF 64 %59 However, the disclosure of the now infamous Enron trading strategies depicted some traders as ruthless and greedy market participants. This coupled with highly questionable accounting practices, has severely eroded investor confidence in many entities that engage in the trading of gas or electricity.
The 8.S. Federal Energy Regulatory Commission has been assailed by members of Congress and by reports by the General Accounting Office expressing doubt about the Commission’s commitment to effective market oversight. The Commission has been criticized for its failure to protect consumers when markets spiraled out of control in the Western United States. The confidence in markets acting as a surrogate for traditional cost-of-service regulation has eroded somewhat. All of this has called into question the integrity of energy marketing and trading. One Senator even announced that he might vote to abolish FERC.
In response, the Commission has embarked upon a multi-pronged strategy to restore necessary confidence. It has devoted significant efforts to an ongoing investigation of Western electric and gas markets, in the wake of the Western energy crisis and the Enron debacle. In February 2002, a thorough investigation of Western market manipulation was instigated. The interim report concluded that the published indices for natural gas spot markets in California were unreliable and may have been manipulated by market participants.
The Commission has also opened new 206 proceedings against six market participants suspected of manipulation or violations of the Commissions’ standards of conduct. The Commission has created a new market monitoring and investigations unit to act as our early warning system, to advise the Commission immediately if a market is spinning out of control.
There is also a growing concern, fueled in part by the significant changes in the energy industry. The brisk pace of mergers and consolidations in both the gas and electric sectors has increased the number of physical and financial transactions between pipeline affiliates. The Commission considers that the current regulations governing the relationship between transmission providers and their gas affiliates must be strengthened and inclusive of all energy affiliates, not just gas marketing affiliates.
Last September, the Commission issued a Notice of Proposed Rulemaking that would cover the relationship among all of the affiliates of a pipeline or transmission provider. In this vein, the Commission announced a Notice of Proposed Rulemaking to establish limits on the amount of funds that can be taken from a regulated subsidiary by a parent company under a cash management program. The impetus for this rulemaking arose from an audit of several pipelines and their parent companies by the Commission’s Office of Chief Accountant.
In addition to the Commission’s rulemaking proceeding, the Office of Chief Accountant issued a detailed guidance to all jurisdictional public utilities, natural gas pipelines and oil pipelines on how jurisdictional entities must account for money pool arrangements, and the types of documentation that must be maintained.
8.4.3. UK (Transco)
After the start of the opening up of the gas market, firstly to industrial and commercial competition and then to the domestic market, the opening up of equal access and subsequent separation of the gas transmission business began. This started with the formulation of the Network Code, which governs the conditions under which gas is transmitted and which all parties had to agree to. For Transco, this was a very large undertaking. The timescale was incredibly ambitious – two years compared to the 10 years to implement a far simpler system in the USA. The result was a very substantial cost for Transco both in terms of manpower and money. Although the new arrangements worked, it was clear from the outset that modifications would be required.
(QHUJ\,QWHUQDWLRQDO,QF 65 %59 The process of modification and reform is ongoing – replacement of the Flexibility Mechanism, introduction of the On-the-day Commodity Market for gas trading, price controls, monopoly and merger investigations, unbundling etc.
The balancing and trading arrangements were seen to be inadequate when there were supply constraints at the St. Fergus terminal. Transco had to take balancing actions, which led to large costs being passed back to shippers. This resulted in the Reform of the Gas Trading Arrangements by Ofgem. There have also been suggestions that some shippers have been manipulating the gas trading market. Although Ofgem has investigated and concluded that there was no supporting evidence of such action, the concerns do not seem to have gone away.
From the outset, a main objective of the Government, through the Regulator, has been to drive down the cost of gas to industrial, commercial and domestic customers. Whereas this has been successful, there have been comments that the extent of regulation had become too extensive. Regulatory controls over gas supply prices to these groups have now been removed.
Although Transco has the option to challenge the orders issued by the Regulator, it has chosen not to and has ultimately agreed. Those functions not essential to gas transportation have either ceased or been separated off. There have been large-scale redundancies. Also Transco has undergone a large number of re-organizations, which has undoubtedly affected morale. One particular consequence is a shortage of qualified engineers.
In the plans for restructuring for its new five-year regulatory cycle, Transco is expected to have some 2,400 fewer employees by 2003, a reduction of 18% on the comparable base of 13,700 in 2001.
Safety is a matter of concern for both the Regulator, and Transco has had to accelerate its programme for replacing iron gas mains with high integrity polyethylene pipes.
The review of the mechanism for revaluing Transco’s Assets by the Regulator has been settled, but if the original proposals had been followed through, some US $100 per domestic consumer would have been returned through price reductions. The effect on forward investment by Transco might have been serious. There seems to be some doubt as to whether the introduction of gas capacity auctions provides the necessary signals for Transco for the long-term investment in the gas pipeline network.
Capacity auctions were adopted by Transco as a means of introducing effective competition where the demand was likely to exceed supply. There has been criticism by the Shippers regarding high prices and the frequency of auctions. Transco introduced modifications to the auction regime.
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8.5.1. VENCorp
5HJXODWRU\
• The Australian Competition and Consumer Commission (ACCC) is the independent statutory authority which administers the 7UDGH3UDFWLFHV$FW and the 3ULFHV6XUYHLOODQFH$FW and has responsibilities under other legislation
• The Commission is the designated regulator for gas transmission pipelines in all states and Territories (except) WA) and for transmission pipelines in the Northern Territory
(QHUJ\,QWHUQDWLRQDO,QF 66 %59 • Under the Government’s legislation, independent State and Territory agencies regulate gas distribution access and pricing
• The ACCC sets the Market and System Operation Rules (MSO Rules) that define the rights and obligations of all users of the principal transmission system and the wholesale gas market in Victoria
• There are set fees that ACCC is required to charge for certain applications and services, such as authorization applications, notifications, exemption orders, access arrangements
The National Third Party Access Code for Natural Gas Pipeline systems (The National Gas Code) sets out the procedure which governs the arrangements for pipeline operators to sell transmission and distribution services to gas producers, retailers and users:
• VENCorp and Parties shipping gas operate under Access Arrangements that define the terms, condition and tariffs
• VENCorp operates under the MSO Rules
&RQWUDFWXDO
Parties operating in the gas market register with VENCorp, provide the necessary financial security and sign agreements as follows:
1. Gas Transportation Deed
2. Distribution Use of System Agreement
2SHUDWLRQDO
q Nominations for the injection or withdrawal of gas are made
• VENCorp schedules the gas
• The system is balanced to meet the demand using daily price signals
• If the system is congested, re-scheduling can be made according to a prior ‘Authorized Daily Amount’
• Line pack can be used to aid balancing, but the amount available is small
• After the gas day, metering data is collected and VENCorp sets the market price based on final demand
• Market participants settle at this price
• Injection/withdrawal adjustments made and bills sent out
• Settlements made at the end of each calendar month
• VENCorp uses an electronic Market Bulletin Board that can be accessed by system users
(QHUJ\,QWHUQDWLRQDO,QF 67 %59 • Under Government rules, the system has to be as transparent as possible and a wide range of information is published on the VENCorp Web site
• VENCorp publishes an annual five planning review
8.5.2. Nicor
5HJXODWRU\
• Under the Natural Gas Act (NGA) of 1938 and other subsequent acts, the Federal Energy Regulatory Commission (FERC) regulates both the construction of pipeline facilities and the transportation of natural gas in interstate commerce
• Companies providing services and constructing and operating interstate pipelines must first obtain Commission certificates of public convenience and necessity
• Nicor’s intrastate activities are under the jurisdiction of the Illinois Commerce Commission
• Nicor, as both the gas transporter of the Chicago Hub and a natural gas distribution company in Illinois, has a regulatory obligation to prioritize its gas distribution operation.
&RQWUDFWXDO
• Shippers requiring to move gas on the Hub, sign a Hub Service Agreement
• For each nomination, a Hub Transaction Request and Agreement form must be signed
• Shippers make their own arrangements to exit gas from the Hub
• Shippers requiring a park and loan service sign a Hub Service Agreement
• Firm gas customers can sign for a Firm Backup service
2SHUDWLRQDO
• Nicor principal business is short-term interruptible gas transportation, although a limited amount of firm gas may be offered
• Shipper makes nominations by Electronic system, E-mail, Fax or Telephone
• Nicor schedules gas on a day-to-day or advance day basis
• Shippers can buy or sell gas and capacity on the electronic Gas Exchange system
• Nicor logs any title transfers for
• Nicor balances daily using its recording devices
• Nicor achieves balancing using a priority system starting with storage
• To maintain system security on designated ‘critical days’, restrictions apply
(QHUJ\,QWHUQDWLRQDO,QF 68 %59 • All transportation /wheeling and storage gas is accounted for by Nicor on a daily basis
• Nicor offers, a storage banking service, charging an excess storage fee where appropriate
• To support the operation, Nicor has various information tools, including:
o Gas Exchange Web based site o Gas Exchange Bulletin board o Information database o Electronic gas transportation customer service o Electronic transaction and administration services
8.5.3. Alliance Pipeline L.P. (USA)
5HJXODWRU\
• Under the Natural Gas Act (NGA) of 1938 and other subsequent acts, the Federal Energy Regulatory Commission (FERC) regulates both the construction of pipeline facilities and the transportation of natural gas in interstate commerce.
• Companies providing services and constructing and operating interstate pipelines must first obtain Commission certificates of public convenience and necessity
&RQWUDFWXDO
• Shippers sign either a Firm or Interruptible Transportation Agreement
• 15 year ‘ship or pay’ contracts
• Regulated tariff with a negotiated element
• Secondary market parties, approved by Alliance USA and on the Approved Bidders List, can bid for capacity released by shippers
• Approved bidder signs a Master Capacity Agreement
• Alliance USA confirms a Capacity Release Schedule to the replacement shipper
2SHUDWLRQDO
• Shipper determines available capacity via the Internet
• Shipper submits daily nomination for gas using the Electronic Delivery Mechanism (EDM)
• Shipper states receipt and delivery details
• Shipper can change nominations on the EDM
• Shipper can release unwanted capacity for auction to approved bidders
• Alliance USA schedules transportation capacity to maximize throughput
• Alliance USA confirms that upstream and downstream pipeline operators can move the gas
(QHUJ\,QWHUQDWLRQDO,QF 69 %59 • Shipper advised of the arrangements
• Alliance USA balances the system using linepack and operating balancing agreements with interconnecting facilities
• Shipper may have to take action to correct imbalance and pay a penalty if the specified tolerance is exceeded
• The EDM records the actual amount of gas moved
• Alliance USA sends invoice to shippers each month
• Payment made by electronic fund transfer
• The EDM is used as a wide-ranging information service for shippers and subscribers, including sending operational and transactional reports
8.5.4. Transco
5HJXODWRU\
• Transco needs licence from Ofgem
• Shipper needs licence from Ofgem
&RQWUDFWXDO
• Transco and shipper agree terms as defined by Network Code
• Transco and shipper sign Framework Agreement (key terms)
• Transco and shipper sign Ancillary Agreement (transportation agreements)
• Transco and shipper sign Network Exit Agreement (terms and conditions for taking gas off system)
2SHUDWLRQDO
• Shipper sends supply point nomination to Transco
• Transco sends offer giving cost of transporting gas
• Shipper accepts and sends confirmation
• Shipper obtains entry capacity via capacity auctions
• Majority as monthly capacity auctions
• Daily auctions to meet needs for individual day
(QHUJ\,QWHUQDWLRQDO,QF 70 %59 • Transco books National Transmission System (NTS) exit and Local Distribution Zone (LDZ) capacity
• Shipper may trade capacity
• Details registered with Transco
• Transco updates information
• Transco schedules gas transportation route
• Shippers and Transco can trade daily entry capacity for firm and interruptible gas
• Shippers trade gas on the On-the-Day Commodity Market (OCM)
• OCM operator informs parties of their trades on the AT Link
• OCM operator sends details to Transco and Transco adjusts accordingly
• OCM operator bills or credits shippers by invoice
• Transco ‘buy’ or ‘sell’ bids to balance
• Transco uses line pack/storage/ interruptibles as necessary
• Transco transports the gas
• Gas is metered
• Gas is allocated to shippers
• Non Daily Metered (NDM) sites are attributed
• Balancing - shippers are paid or charged for extra gas used or insufficient gas taken
• Reconciliation when NDM meter readings are available
• Transco calculates charges
• Transco sends invoices
• Transco and shipper performance reports are sent to shippers and Ofgem
• Regular financial audits of Transco’s actions take place
• Transco sends out operation reports and network operation reports
(QHUJ\,QWHUQDWLRQDO,QF 71 %59 $33(1',;*/266$5<2)7(506
$GYDQFHG5HVHUYDWLRQRI&DSDFLW\$JUHHPHQW $5&$ A long term agreement between Transco and Shippers for future NTS pipeline capacity for large sites. Allow shippers to reserve exit capacity well in advance of first gas flows.
$QQXDO 4XDQWLW\ $4 The AQ of a supply point is its annual consumption over a year, under conditions of average weather.
%DVH3ODQ $VVXPSWLRQV (BPA) A document produced by Transco on an annual basis that describes Transco’s supply and demand forecasts for the next ten years that underpin its current investment planning process.
&DSDFLW\ The amount of gas that can be held within the physical structures (pipeline and storage facilities).
&DSDFLW\ (deliverability) The daily rate at which energy can be withdrawn from a storage facility.
&DSDFLW\ (entry) The amount of gas that a shipper is entitled to put into the system at a particular input point (terminal) on a day.
&DSDFLW\ (exit) The amount of gas that a shipper is entitled to withdraw from a pipeline system in order to meet the requirements of its customers on a day.
&DSDFLW\ (space) The amount of energy that can be stored at a storage facility.
&DSDFLW\7UDGLQJ The process by which shippers with spare capacity sell it to other shippers that require more capacity through a process of offers and bids
&RPSRVLWH :HDWKHU 9DULDEOH (CWV) A single measure of weather for each LDZ, incorporating the effects of both temperature and windspeed. A separate composite weather variable is defined for each LDZ.
&RPSUHVVRU6WDWLRQAn installation that uses gas (or electricity) powered jet engines to boost pressures in the pipeline system. Used to increase transmission capacity and move gas through the network.
&RQQHFWHG6\VWHP([LW3RLQW &6(3 A connection to a more complex facility than a single supply point. For example a connection to a pipeline system operated by a Gas Transporter other than Transco.
'DLO\&DSDFLW\%LGA bid to buy capacity from Transco in the daily capacity auctions
'DLO\&DSDFLW\2IIHUAn offer to sell capacity back to Transco through the capacity surrender mechanism
'DLO\ 0HWHUHG 6XSSO\ 3RLQW A supply point fitted with equipment that enables meter readings to be taken on a daily basis.
([LW=RQHA geographical area (within an LDZ) that consists of a group of supply points that, on a peak day, receive gas from the same NTS off take. (QHUJ\,QWHUQDWLRQDO,QF 72 %59 )DOFRQ A computer program Transco uses to simulate the operation of the transmission system. It is used to optimize future system expansion plans as supply and demand change overtime.
*DV7UDQVSRUWHU (GT) A company licensed under the Gas Act by Ofgem to transport gas to consumers. Transco if the largest GT in Great Britain.
,QWHUFRQQHFWRUA pipeline transporting gas from Great Britain to another country.
.LORZDWWKRXU (KWh) A unit of energy. Approximately equal to 0.0341 therms.
/LQHSDFNStorage in the pipeline system itself or, more simply, the volume of gas within the National or Local Transmission System at any time.
/LTXHILHG 1DWXUDO *DV (LNG) Gas stored in liquid form. Can be firm or constrained (CLNG). Shippers who book constrained service agree to allow Transco to use some of their gas to balance the system.
/RFDO'LVWULEXWLRQ=RQH (LDZ) A geographic area supplied by one or more NTS offtakes. Consists of LTS and Distribution System pipelines.
/RQJ 5XQ 0DUJLQDO &RVW (LRMC) The methodology used by Transco to determine NTS capacity charges, based on the cost of reinforcing the system to carry a 29.87 Gwh per day increase in demand sustained over 10 years.
/RFDO7UDQVPLVVLRQ6\VWHP /76 The pipeline system that takes gas from NTS offtakes and transports it to the Distribution system and direct to some large users.
1DWLRQDO%DODQFLQJ3RLQW 1%3 A notional point on the NTS used as the point of delivery for many gas supply contracts.
1DWLRQDO 7UDQVPLVVLRQ 6\VWHP (NTS) Transco’s high pressure network of pipes used to transport gas in bulk around the country.
1DWLRQDO7UDQVPLVVLRQ6\VWHP2IIWDNHAn installation defining the boundary between the NTS and LTS or a very large consumer. The off take installation includes equipment for metering, pressure regulation, etc.
1HWZRUN &RGH A document that defines the contractual relationship between Transco and System Users.
1HWZRUN([LW$JUHHPHQWV (NExA) A contractual agreement that is ancillary to the Network Code. A NExA can be entered into between Transco and a shipper or end customer, where the offtake from the NTS consumes in excess of 58.6 GWh (2 million therms) per annum. The NExA sets out a number of provisions relating to the flow of gas at the offtake. These provisions include details of offtake pressure, Notice Periods, numbers of allowed Maintenance Days, and specified Communication and Metering Equipment.
1HWZRUN6HQVLWLYH/RDG 16/ A site where by virtue of its location on the pipeline, Transco requires its specific interruption to maintain the supply of gas to firm supply points in the same. At present, all NSL’s are located at the LDZ level. This category of interruptible supply point is more likely to be called upon to interrupt due to their location near positions of network transportation constraints. This is especially true during mild winters.
1RQ 'DLO\ 0HWHUHG 1'0 A meter that is read monthly or at longer intervals. For the purposes of daily balancing, the consumption is estimated, using an agreed formula, and for the supply points consuming more than 73.2 MWh pa, reconciled individually when the meter is read.
(QHUJ\,QWHUQDWLRQDO,QF 73 %59 2IJHPOffice of Gas and Electricity Markets (the UK regulator for both gas and electricity, previously separate as Ofgas and Offer).
2SHUDWLQJ0DUJLQVGas used by Transco to maintain system pressures under circumstances including periods immediately after a supply loss or demand forecast change before other measures, such as the flexibility mechanism, become effective, and in the event of plant failure, such as pipe breaks and consumer trips.
3HDN GD\ GHPDQG LQ 3HDN GHPDQG The 1 in 20 peak day demand is the level of demand that, in a long series of winters, with connected load held at the levels appropriate to the winter in question, would be exceeded in one out of 20 winters, with each winter counted only once.
3URGXFHU Company which explores for gas, drills the wells, and flows the gas from the seabed. It sends the gas along undersea pipelines and hands it over to terminal operators
6HDVRQDO1RUPDO&RPSRVLWH:HDWKHU9DULDEOH 61&:9 The seasonal normal value of the CWV for a LDZ on a day is the smoothed average of the values of the applicable CWV for that day in a significant number of previous years (currently 65 such historical years of data).
6KLSSHUA company that contracts with the pipeline company for the use of transportation and storage facilities.
6WDQGDUG ,QWHUUXSWLEOH 61, An interruptible supply point which allows Transco to interrupt the site for up to 45 days each year. Such a contract provides the site with relief from some capacity charges.
6XSSOLHUA company with a Supplier’s licence contracts with a shipper to buy gas which is then sold to consumers. A supplier may also be licensed as a shipper.
6XSSO\2IIWDNH4XDQWLW\ 624 The maximum daily consumption at a supply point.
6XSSO\3RLQWA group of one or more meters at a site.
7UDQVFRVWA PC-based network simulation model which can be used to examine the effect of supply/ demand changes on required system reinforcements and thus determines the Long Run Marginal Cost. It is not a rigorous engineering planning tool, but it produces results that are comparable to FALCON. It gives a rapid result by virtue of making a number of simplifying assumptions in the calculation process.
7UDQVFR 1RPLQDWHG ,QWHUUXSWLEOHV 71, Interruptible site that Transco may need to interrupt for more than 45 days during a 1 in 50 winter. Under network code rules, Transco must give at least 12 months notice of such a designation.
7RS8STransco sets a monitor level at storage sites. These monitor levels represent Transco’s estimate of the volume of gas in store needed at different times of the year to ensure that the security standards can be met. If there are insufficient shipper booking to reach these monitor levels, Transco makes ‘Top Up’ purchases up to the monitor level to ensure that the security standards can be met.
8./LQNA suite of computer systems that supports Network Code operations. Includes AT- Link for energy balancing, Supply Point administration; and the Sites and Meters database
(QHUJ\,QWHUQDWLRQDO,QF 74 %59 $33(1',;2)*(0&+5212/2*<±
JANUARY 2000- 8WLOLWLHV%LOO– a major piece of legislation
The Utilities Bill begins it passage through parliament. It puts a primary duty on utility regulators to protect the customer interest and provides for a framework for future regulation to reinforce competition. It provides for the creation of Gas and Electricity Markets Authority (GEMA) with the regulator as chairman.
The Government reveals that the Utilities Bill allows for the future Energy Efficiency Standards of Performance (EESOP) obligation to be decided by the Government.
7UDQVFRWUDQVIHUVEXVLQHVVHVA consultation paper is issued by Ofgas which seeks views on Transco’s proposals to transfer three subsidiary businesses, which deal with training, pipeline maintenance and engineering, to BG Technology Ltd.
FEBRUARY 2000 - 2IJHPDQQRXQFHVQHZGHSDUWPHQWDQGDSSRLQWPHQWV
New appointments: As a result of the provisions in the Utilities Bill, Ofgem announces a new post of General Council to manage the legal services and resources. Also a new department will be created to manage the governance of the new Gas and Electricity Markets Authority.
&KDQJHVWRQHZ JDV WUDGLQJ DUUDQJHPHQWV Changes are made to the New Gas Trading Arrangement, which will allow Transco to buy or sell additional capacity on the gas day.
MARCH 2000 - 6RFLDO$FWLRQ3ODQSXEOLVKHG
The scheme will run until March 2002 and then the responsibility for energy saving will transfer to the DETR. New efficiency standards for gas and electricity companies will be established. Companies will be set energy saving targets, based on the number of customers they have.
&KDQJHVWRJDVDFWThe Department of Trade and Industry (DTI) announces proposals to use its existing powers to make changes to the Gas Act 1986, which would make it easier for industrial and commercial customers to check the accuracy of information held on them by Transco.
APRIL 2000 - $XFWLRQVRI/1*VWRUDJHFDSDFLW\
Interim arrangements are issued by Ofgem which allow for BG Transco’s liquid natural gas (LNG) storage capacity to be sold by auction to gas shippers.
BG Transco’s proposals to reduce National Transmission charges, following the revenue over- recovery during March monthly entry capacity auctions, are accepted by Ofgem.
MAY 2000 - 3URSRVDOVRQSULFHFRQWUROVIRU7UDQVFR
Ofgem issues proposals directed at Transco which cover planned price controls, long-term investment and the future of metering and meter reading. The review on price control from April 2002 proposes separate price controls for each of the 12 national Local Distribution Zones (LDZs) in Transco. The proposals on long-term investment are intended to sharpen the incentives on Transco to invest in a timely and efficient way. Ofgem proposes that separate price controls are introduced immediately on Transco’s metering and meter reading activities.
(QHUJ\,QWHUQDWLRQDO,QF 75 %59 JUNE 2000 - 2IJHPDFWVRQPHWHULQJFRPSODLQWV
Following complaints about the way in which British Gas handled final meter readings and the delays in issuing final bills for transferring gas customers, British Gas developed new procedures which Ofgem believe will improve the service to customers.
JULY 2000 -2IJHPUHGXFHVXQQHFHVVDU\OLFHQFHFRQGLWLRQV
In response to concerns about the burden of regulation, Ofgem issues proposals to reduce unnecessary licence conditions. It is their opinion that the protection presently provided by ‘non- discrimination conditions’ can be offered by taking action under the Competition Act. This would then allow Ofgem to concentrate on developments in the gas and electricity supply markets which have an anti-competitive effect.
5HYLHZRIQHZJDVWUDGLQJDUUDQJHPHQWVA review of the new gas trading arrangements has been undertaken and published by Ofgem. The March capacity auctions had attracted criticism from companies and large customers. Ofgem found that the new system had worked well compared with its predecessor and that the costs of balancing the system fell from £10 million to £7 million between winter 1998/1999 and winter 1999/00. The review found no evidence of market abuse by companies, although a number of weaknesses were identified.
The Utilities Act receives Royal Assent.
2IJHP LVVXHV (QYLURQPHQWDO $FWLRQ 3ODQ The environmental and social objectives identified under the new Utilities Act result in Ofgem issuing proposals for an Environmental Action Plan. Ofgem comments that the activities of gas and electricity companies have an important impact on the environment and that the way that these companies are regulated needs to be taken into account.
AUGUST 2000 - 2IJHPUHYLHZVFRPSHWLWLRQLQJDVPDUNHW
A review of competition in the industrial and commercial gas supply market is published by Ofgem. This finds that:
Customers switch suppliers in response to changes in relative prices Few complaints about entry barriers to the market.0RUHWKDQVKLSSHUVDQGVXSSOLHUVDUHQRZFRPSHWLQJLQWKHPDUNHW
A fall in British Gas Trading’s overall market share to about 20% by volume.
Four shippers/suppliers with more than 10% of market share.
8WLOLWLHV$FWILQDQFLDOSHQDOWLHVUnder new powers established by the Utilities Act 2000, Ofgem will be able to impose a financial penalty on any gas or electricity licence holders who have breached or are breaching their licence conditions. Accordingly, Ofgem announces that it is seeking views on how it might use these new powers.
1HZ(OHFWULFLW\7UDGLQJ$UUDQJHPHQWVAlthough not specifically a gas regulation matter, it is worth noting that the New Electricity Trading Arrangements (NETA) were introduced during this month. NETA provides for genuine competition in the wholesale electricity market and it will replace the Electricity Pool with long and short term forwards markets and a balancing mechanism and settlement process.
$SSOLFDWLRQIRUHOHFWULFLW\OLFHQFHVUHIRUPHGProposals are announced by Ofgem to reform the way gas and electricity companies can apply for electricity licences. Under the Utilities Act 2000, electricity distribution and supply have been separated and the current 14 Public Electricity Suppliers abolished. This means that electricty distribution will be subject to licensing for the first time.
(QHUJ\,QWHUQDWLRQDO,QF 76 %59 OCTOBER 2000- 6KLSSHUWUDGHV2IJHPFRQFHUQHG
As part of its regular monitoring of the wholesale gas market, energy regulator Ofgem wrote to all shippers, to request information on the volumes of shipper trades at the National Balancing Point and Beach for certain days in August and September. This move was prompted by problems experienced by BG Transco, as a result of shippers’ actions within day, which forced them to buy and sell gas to balance the system at a substantial loss and caused very high prices in the spot market.
Nine days later, Ofgem again wrote to all shippers, expressing concern about the behaviour of a number of companies in the capacity market since 1 October 2000. The letter also states that Ofgem would be writing to a number of individual shippers separately to ask them to explain their recent behaviour – and reminds all shippers that Ofgem has, or will have shortly, powers both under the Gas Act 1986 and the Competition Act 1998 to take enforcement action and to impose financial penalties if there is a breach of licence conditions or the Competition Act. Further to this, Ofgem then specifically requested information from all shippers about the volumes and prices at which they have been trading capacity during the recent period of constraints on Transco’s network.
3HUIRUPDQFHVWDQGDUGVNewly-extended performance standards and how they might apply to all gas and electricity companies in the future are the subject of a consultation exercise) by energy regulator Ofgem. These standards have previously only applied to Public Electricity Suppliers (PESs) and gas suppliers - but they can be set for electricity distributors, gas transporters and all suppliers following the introduction of the Utilities Act 2000. The Act will give the regulator powers to set these standards of performance and, for the first time, impose financial penalties if they are not met.
NOVEMBER 2000- 6WRUDJHFDSDFLW\DXFWLRQV
Reforms in the gas storage market introduced over the last two years were hailed a success by Ofgem. In a review document, Ofgem concludes that the auctions of storage capacity have achieved their aim of increasing and developing competition in the storage market.
0RUHLQIRUPDWLRQWRSURPRWHJUHDWHUJDVFRPSHWLWLRQProposals to increase the amount of information provided to customers and potential customers by gas pipeline operator Transco have been published by energy regulator Ofgem today (Friday).
These proposals - which will be introduced through a special licence condition - have been prompted by complaints from both domestic and industrial and commercial customers about lack of access to information relating to their gas supply.
8SGDWHRQ7UDQVFRSULFHFRQWUROUHYLHZSURJUHVVA progress report on the development of the new Transco price controls is published by Ofgem. The paper reports on progress made by Ofgem in developing the new price controls which are due to apply to Transco from April 2002. This paper follows an initial consultation document published in May and a public seminar which took place in August. The paper is principally designed to keep Transco’s customers and other interested parties informed on progress with the price control review, but it also seeks views on some issues, in particular how to measure the areas of Transco’s performance of most concern to users of its network.
*DVPHDVXULQJFKDQJHVOfgem publishes a consultation document seeking views about the implications of changing the way gas consumption is measured.
DECEMBER 2000- &KDQJHVWR%*7SULFHFRQWURO
Following a review of competition in the domestic gas market, energy regulator Ofgem announces initial proposals to remove the price control for British Gas Trading (BGT) from April 2001.
6WURQJHULQFHQWLYHVSURSRVHGIRULQYHVWPHQWLQWUDQVFR¶VJDVWUDQVPLVVLRQV\VWHP
(QHUJ\,QWHUQDWLRQDO,QF 77 %59 Following an earlier consultation in May, Ofgem issues proposals to improve the way in which Transco invests in transmission capacity on their National Transmission System (NTS) for the gas market. The document sets out the general framework for the new arrangements. Which are aimed at improving the incentives on Transco to invest in a timely and efficient manner to meet the needs of customers. The proposals also aim to improve the signals of the need for new investment in the network on which Transco’s investment decisions are made.
In setting its next price control (effective from April 2002), Ofgem states that Transco’s allowed revenue should be directly related to the outputs it delivers on the NTS.
2IJHP VSHOOV RXW LWV SULRULWLHV IRU Improving competition and industry competitiveness, ensuring efficient trading in wholesale gas and electricity and tackling fuel poverty are among the priorities for energy regulator Ofgem for 2001.
JANUARY 2001- 0DUNHWLQJFRQGLWLRQVSURYLGHIXUWKHUSURWHFWLRQIRUFRQVXPHUV
Domestic and small business gas and electricity suppliers sign up to a range of conditions developed by energy regulator Ofgem which will improve the way that companies market their services and strengthen protection for customers
1HZ OLFHQFH FRQGLWLRQ IRU WUDQVFR WR SURYLGH PRUH LQIRUPDWLRQ WR JDV FXVWRPHUV Gas customers can now get more information from pipeline operator Transco to enable them to take greater advantage of the competitive gas market. Ofgem has agreed a new licence condition which will make information in key areas more widely available.
3ROLF\RQILQDQFLDOSHQDOWLHVVHWRXWE\2IJHPThe factors that Ofgem proposes to take into account when deciding whether or not to impose financial penalties on companies, and in deciding on the scale of those penalties, are announced in a consultation paper. Under the Utilities Act 2000 Ofgem is able to impose financial penalties of up to 10 per cent of turnover if companies contravene licence conditions and certain statutory obligations or fail to meet guaranteed performance standards.
3HUIRUPDQFHVWDQGDUGVSURSRVDOVWRJXDUDQWHHVHUYLFHOHYHOVOfgem sets out its proposals on what standards and performance targets should be set for the monopoly electricity distribution and gas transportation businesses. Under the Utilities Act 2000, guaranteed and overall standards of performance can be set for electricity distributors, gas transporters and all electricity and gas supplier.
FEBRUARY 2001 - 2IJHPRXWOLQHVDSSURDFKWRQH[W7UDQVFRSULFHFRQWURO
The framework of the new Transco price control, due to come into effect in April 2002, is published by Ofgem. The document is the latest stage of the price control consultation process and draws on comments by both Transco and the gas industry about how the price control should be developed.
Among the proposals are:
A separate price control for the National Transmission System (NTS) and the local distribution zones (LDZs)
A single price control for all 12 LDZs - but allowing for consultation on the development of separate controls for each individual LDZ
Improved incentives on Transco to deliver an agreed level and quality of service to customers.
(QHUJ\,QWHUQDWLRQDO,QF 78 %59 )XUWKHUUHIRUPWRJDVWUDGLQJDUUDQJHPHQWVProposals for major reform of the existing gas balancing regime are announced by Ofgem, as part of the continuing development of wholesale gas trading arrangements.
The proposals recommend reforming:
• the existing balancing arrangements, which Ofgem believes are inefficient and can lead to higher prices and balancing costs;
• Transco’s role and incentives to ensure it operates the system as efficiently as possible;
• the way information is provided to customers and gas shippers to ensure transparency and help prevent market distortion
MARCH 2001 - (QHUJ\JXLGHOLQHVRQWKHFRPSHWLWLRQDFW
Guidelines are published by Ofgem that state how it will use its powers under the new Competition Act to investigate and act against anti-competitive activity in the gas and electricity industries. The guideline is issued in conjunction with the Office of Fair Trading (OFT), and follows a consultation held last year
3URSRVDOV WR LPSURYH 7UDQVFR¶V LQYHVWPHQW LQFHQWLYHV Ofgem announces its proposed reforms to the incentive framework relating to investment in Transco’s National Transmission System (NTS).The proposals form an integral part of the current periodic review of Transco’s price control and Ofgem’s ongoing programme of reform for wholesale gas trading arrangements.
These proposals are designed to address concerns expressed by a number of customers, shippers and producers about Transco’s incentives to invest in the NTS in a timely manner. These concerns stemmed from the delay in commissioning new capacity at the St Fergus terminal in 1998 and the subsequent signals emerging from the short term capacity auctions indicating continuing capacity constraints at entry on the network during the summer months
6WUDWHJ\WREULQJGRZQPHWHULQJFRVWVDQGHQFRXUDJHLQQRYDWLRQMeasures to enable gas and electricity customers to benefit from lower cost metering services and take advantage of technological advances in metering are outlined in a strategy announced by energy regulator Ofgem.
JUNE 2001 - ,QFHQWLYHVWRSURYLGHEHVWYDOXHXQGHU7UDQVFRSULFHFRQWURO
Under the Ofgem’s proposals announced by Ofgem, Transco will:
• be asked to agree to output targets for its National Transmission System (NTS) and receive incentives to react to the changing demands of its customers
• receive incentives to minimise the number and duration of supply interruptions and be expected to accept Guaranteed and Overall Standards of service for its customers in its Local Distribution Zones (LDZs).
JULY 2001 - &KDQJHVPDGHWRWKHUHWDLOJDVWUDQVIHUSURFHVV
With gas suppliers set to start contracting out their metering services, Ofgem has drawn the industry’s attention to the need, from 23 July, for gas suppliers to consider ownership of meters when taking on a new customer.
(QHUJ\,QWHUQDWLRQDO,QF 79 %59 AUGUST 2001 - '\QHJ\¶VDFTXLVLWLRQRI%*VWRUDJH¶V5RXJKDQG+RUQVHDVWRUDJHVLWHV
Following the announcement on 16 July 2001 of the sale of Rough and Hornsea by BG Storage to Dynegy, the Office of Gas and Electricity Markets (Ofgem) is issuing a consultation paper on the regulatory issues involved
(QYLURQPHQWDODFWLRQSODQOfgem considers that environmental issues associated with the production, distribution and consumption of gas and electricity are important. Consequentially, Ofgem issued a plan of action setting out the role, responsibilities and policy of Ofgem in relation to the protection of the environment.
SEPTEMBER 2001 - 7UDQVFRV\VWHPRSHUDWRULQFHQWLYHVSURSRVDOV
Ofgem address concerns from customers and industry about the costs they have incurred as a result of constraints on the NTS and puts forward new incentive arrangement proposals for Transco.
Under the proposals, Transco will:
• auction long term capacity rights which can then be traded in secondary markets. Emerging market signals from this trading will help Transco plan future investment
• have strong financial incentives to deliver more capacity than is forecast in the price control - if there is demand from customers
• operate under a series of incentives relating to the costs of day-to-day operation. Under these incentive schemes, Transco will be set target levels of costs.
If Transco exceeds the targets set under the incentives, it will keep a share of the difference. If it does not meet the targets, it will have to pay a proportion of the shortfall. According to Ofgem, Transco can potentially earn £38 million a year extra if it exceeds all its targets.
2IJHP¶VILQDOSURSRVDOVIRU7UDQVFRSULFHFRQWUROOfgem makes the statement that the final proposals for the forthcoming five year price control on gas pipeline operator, Transco are “Firm but fair”.
OCTOBER 2001- 7UDQVFRDFFHSWDQFHRISULFHFRQWUROSURSRVDOV
The acceptance of final proposals for the forthcoming five year price control on gas pipeline operator, Transco, has been welcomed by energy regulator, Ofgem. This is the 32nd price control undertaken by Ofgem, all of which have been accepted without being referred to the Competition Commission. The 32 price controls carried out by Ofgem since 1999 have meant a reduction in company revenues of more than £1 billion, which represents a saving of more than £20 a year on a typical household energy bill.
2IJHP UDLVHV LVVXHV IRU IXWXUH HQHUJ\ SROLF\ According to Ofgem, Government policymakers need to tackle serious issues to ensure that gas and electricity supplies remain secure and diverse and that the benefits of competition and effective regulation are not compromised.
(QKDQFLQJ DVVHW ULVN PDQDJHPHQW VWDQGDUGV LQ JDV DQG HOHFWULFLW\ QHWZRUNV Ofgem plans to issue an annual survey to gauge the current status of asset risk management among gas and electricity network companies. These plans reflect Ofgem’s primary statutory role to protect customers’ interests.
(QHUJ\,QWHUQDWLRQDO,QF 80 %59 NOVEMBER 2001 - &RPSHQVDWLRQIRUWKLUGSDUW\VXSSO\LQWHUUXSWLRQV
Following discussions between Transco and Ofgem, all domestic customers who find themselves without gas through the actions of a third party, such as a water company or a cable operator, will receive £20 compensation from Transco for every 24 hours they are off supply.
,QYHVWLJDWLRQE\2IJHPLGHQWLILHVQHHGIRULPSURYHPHQWVWRFDSDFLW\UHJLPH
Gas capacity market investigation concluded
• No further action planned as no evidence of anti-competitive conduct found
• Improvements to capacity arrangements identified
• Improvements addressed through Ofgem’s Transco system operator incentives proposals
DECEMBER 2001 - (QIRUFHPHQWRUGHURQ7UDQVFR
An Enforcement Order (the Order) imposed on gas pipeline operator Transco, to tighten up the way it operates its connections activities is to be kept in place by energy regulator Ofgem. The Order, imposed by Ofgem’s predecessor, Ofgas, in February 1999, was prompted by an investigation which found significant shortcomings in the way Transco conducted its connection operations.
,QFHQWLYHVVWUHQJWKHQHGLQ7UDQVFR176V\VWHPRSHUDWRUILQDOSURSRVDOVFinal proposals that build on and strengthen initial plans for system operator incentive arrangements applying to gas pipeline operator Transco were announced by energy regulator Ofgem.
For the first time, Transco will have to make available defined levels of entry and exit capacity for each year of its five year price control.
FEBRUARY 2002- 1HZHQHUJ\VDYLQJWDUJHWV
Energy efficiency targets that could help gas and electricity customers save over £100 a year on their heating bills announced by Ofgem.
0DMRUUHIRUPSURSRVDOVWRJDVEDODQFLQJUHJLPHProposals for major reforms to the way the national gas pipeline system is operated and kept secure through a competitive wholesale gas market are unveiled by Ofgem.
• proposed reforms will enable Transco to operate a secure and efficient National Transmission System (NTS)
• shorter balancing periods than one day proposed
• on us on shippers to tell Transco how much gas they will deliver, or take off, at any one time
• shippers to face full costs of any behaviour which forces Transco to take balancing action
APRIL 2002 - 2IJHPSXEOLVKHVILUVWHYHUWKUHH\HDUSODQ
The themes driving Ofgem’s work will be:
• making markets work effectively (QHUJ\,QWHUQDWLRQDO,QF 81 %59 • regulating monopoly business intelligently
• securing Britain’s gas and electricity supplies
• meeting Ofgem’s social and environmental responsibilities, and developing Ofgem’s effectiveness and efficiency.
MAY 2002 - 2IJHPFRQVXOWVRQ1*&DQG7UDQVFRPHUJHU
Energy regulator Ofgem announced it is to consult on the proposed merger of National Grid Group plc and Lattice Group plc.
5HIRUP RI WKH JDV EDODQFLQJ UHJLPH Ofgem confirmed its commitment to the gas industry’s initiatives to examine the long-term future of the gas balancing regime. This follows the publication by Ofgem, of revised proposals to reform the balancing regime published in February 2002.
AUGUST 2002 - 0RQRSRO\SULFHFRQWUROV
A consultation paper, seeking views on how to improve the framework of price controls on monopoly gas and electricity networks, is published by Ofgem.
SEPTEMBER 2002 - 1HZORQJWHUPHQWU\FDSDFLW\DXFWLRQV
New entry capacity auctions are approved by will increase efficiency and security of supply by providing long-term access to Great Britain’s gas pipeline system (National Transmission System NTS).
(QHUJ\,QWHUQDWLRQDO,QF 82 %59 $33(1',;&+5212/2*<)257+((67$%/,6+0(17$1'())(&762) 5(*8/$7,21,17+(8.*$60$5.(7
JULY
The Gas Act is granted Royal Assent.
It provides for :
• The privatisation of the British Gas Corporation.
• The establishment of a regulatory regime, Ofgas, as the gas industry watchdog; and
• Establishing a formal role for the Gas Consumers Council to represent the interests of the consumer.
AUGUST
James McKinnon is appointed as the Director General of Gas Supply.
DECEMBER
British Gas shares float on stock market at £1.35. British Gas is worth £5.6 billion.
The market above 25,000 therms per annum opens to competition.
NOVEMBER
British Gas is referred to the Monopolies and Mergers Commission (MMC) by the Director General of Fair Trading (DGFT) over the alleged discrimination in the non-tariff market.
APRIL
Ofgas asks British Gas to publish standards of service.
OCTOBER
The MMC publishes its report on price discrimination in the non-tariff market.
The report upholds complaints over British Gas pricing requiring British Gas to:
• Limit buying of North Sea Gas to 90%;
• Set prices in the industrial market according to published schedules; and
• Stop undue discrimination.
(QHUJ\,QWHUQDWLRQDO,QF 83 %59
APRIL
British Gas accepts changes proposed by Ofgas concerning the handling of customers threatened with disconnection.
MAY
Following direction from Ofgas, Agas becomes British Gas’ first competitor to have access to the existing pipeline.
OCTOBER
Quadrant Gas is launched as the first independent gas supplier.
FEBRUARY
British Gas signs undertakings with the Secretary of State for Trade and Industry (henceforth the Secretary of State), which bring compliance with the recommendations of the MMC.
MARCH
The first alternative gas supplier, Quadrant Gas, enters the non-tariff market.
JUNE
Ofgas announces plans to review tariff price formula.
DECEMBER
New competition targets are set by Ofgas for British Gas in order to increase the competitive market share to 30 per cent by October 1993.
MARCH
The issuing of a pricing structure and policy for gas supplies to power stations, which reflects the balancing of British Gas’ operational requirements against the increasing demand to supply, causes problems with the Regulator. Ofgas issues an enforcement order to British Gas, to ensure that it lowers prices charged to power stations. Ofgas is of the opinion that British Gas has broken its legal requirement to set prices in the interruptible market at a level designed to keep supply and demand in balance. This is also seen as anti-competitive practice by other power station suppliers.
APRIL
To avoid a referral to the MMC, British Gas accepts a tariff formula of Retail Price Index (RPI) -5, up from RPI-2 and agrees to accept responsibility for managing its share of the contract gas market above 25,000 therms per annum, down from 95% to 40% by the calendar year 1995.
JULY
British Gas backs down in the power station dispute and sets new prices in line with supply cost. (QHUJ\,QWHUQDWLRQDO,QF 84 %59 OCTOBER
The Office of Fair Trading’s (OFT) report on the development of competition in the non-tariff market since the 1988 MMC report is published. The report reviews the progress made towards competition and calls for an end to monopoly in the tariff market (customers consuming below 2500 therms per year).
MARCH
Competition and Service (Utilities) Act 1992 is granted Royal Assent, allowing the Secretary of State to lower or abolish the tariff market threshold.
The Act extends Ofgas powers in respect to standards of service and enables annual targets to be established to improve British Gas’ services to customers.
APRIL
A new British Gas price control (RPI-5) comes into force, providing for a second price-cap formula for British Gas. It also includes a standards of service package.
JULY
The Secretary of State makes two referrals to the MMC under the Fair Trading Act 1973 concerning British Gas. The first concerns the whole of the gas industry and, the second refers to the specific question of the separation of British Gas’ transportation and storage activities from its supply arm.
The Gas (Modification of Therm Limits Order) Order 1992 reduces the threshold for the competitive gas supply market from 25,000 to 2,500 therms.
Sir James McKinnon, Director General of Gas Supply (DG), asks the MMC to investigate whether the operation by British Gas of its transportation and storage business operates, or is likely to operate, against the public interest.
AUGUST
The DG makes a further referral to the MMC, asking it to investigate the fixing of tariffs for the supply of gas by British Gas.
AUGUST
MMC recommends abolition of British; Gas’ monopoly of supply to smaller customers and divestment of its trading arm.
NOVEMBER
Clare Spottiswoode succeeds Sir James McKinnon as Director General of Gas Supply.
DECEMBER
Michael Heseltine, President of the Board of Trade, announces a response to the MMC’s recommendations, including:
(QHUJ\,QWHUQDWLRQDO,QF 85 %59 • A timetable for the introduction of competition in the domestic market; and
• Separation of British Gas’ transportation and storage and trading arms by regulation rather than requiring separate ownership.
FEBRUARY
Ofgas amends British Gas’ price controls for domestic customers to RPI-4 in accordance with MMC recommendations.
MARCH
British Gas replaces its regional structure with five separate business units. The transportation and storage business, British Gas Transportation and Storage, is established as one of the units.
APRIL
The third price-cap formula for British Gas comes into force. British Gas Transportation and Storage is renamed British Gas Transco.
MAY
Competition and Choice in the Gas Market is published detailing the Ofgas/DTI proposals for extending competition into the domestic market.
JUNE
Ofgas announces price control proposals for the transportation and storage of gas (RPI-5).
SEPTEMBER
Ofgas relaxes the requirement on British Gas to publish price schedules for firm gas above 25,000 therms.
OCTOBER
British Gas’s transportation and storage business is subject to a separate price control from supply for the first time.
NOVEMBER
Ofgas states that British Gas’ price increases - 2.9%, effective from January 1 - are allowable within Ofgas’ price control.
FEBRUARY
Ofgas announces its decision on the separation of British Gas’s trading activities from its transportation and storage activities, including full physical separation and “Chinese Walls” to prevent unnecessary information flows from Transco, the transportation business, to the trading business.
MARCH
(QHUJ\,QWHUQDWLRQDO,QF 86 %59 Ofgas declares that British Gas must agree to meet certain criteria if it wishes pricing according to published schedules in the Industrial and Commercial market to cease.
DTI announces the areas to be included in the first phase of competition in the domestic market - these cover 500,000 consumers in Devon, Somerset, and Cornwall.
MAY
Ofgas decides that British Gas’ Direct Pay tariff- offering a 5% discount for those who pay by direct debit - is not discriminatory.
JUNE
DTI announces areas to be included in the second phase of the introduction of competition in the domestic market - these cover a further 500,000 of consumers in the South West and 1 million consumers in the South East.
The regulator raises questions British Gas’ new OptionPay tariff which offers discounts for domestic customers who pay their bills within 10 days.
Ofgas suspends the requirement making British Gas price according to published schedules in the Industrial and Commercial market.
Ofgas publishes a consultation paper inviting views on the price control that will govern Transco’s transportation and storage prices from April 1997.
Ofgas issues a discussion paper about the liabilities Transco should pay to independent shippers, in the event that it delivers poor service.
SEPTEMBER
Ofgas publishes a discussion document looking at the way Transco’s Network Code might evolve after it is introduced in March 1996.
OCTOBER
British Gas’s UK business is further restructured with the Public Gas Supply and Business Gas units merging into a single business unit, British Gas Supply
NOVEMBER
The Gas Act 1995 is granted Royal Assent. It introduces a new regulatory framework ahead of the liberalisation of the domestic supply market.
Ofgas issues a consultation document about the control of prices to British Gas’ domestic customers. The new price control is set to come into effect in April 1997.
DECEMBER
By the end of 1995, there were 40 independent gas marketing companies selling gas to UK businesses. They had captured 80% of the firm industrial and commercial market and 70% of the market for interruptible sales. Producers were now selling gas on a short term basis to shippers and traders and the spot market for gas developed.
Ofgas publishes a progress report on the 1997 price control review for Transco’s Transportation and Storage services.
(QHUJ\,QWHUQDWLRQDO,QF 87 %59
JANUARY
Ofgas confirms April 1 as the target date for the start of domestic competition in the South West.
FEBRUARY
The Gas (Northern Ireland) Order 1996 enters into force.
Ofgas welcomes the Gas Transfer Scheme, which legally separates the trading and transportation arms of British Gas, beginning March 1.
British Gas agrees to re-examine how much it charges different groups of domestic customers, following an Ofgas review of its Optionpay tariff.
Ofgas publishes the 1995 Annual Report and predicts lower prices for domestic consumers with the opening up of competition.
A new guide for domestic gas customers in the South West is published by Ofgas.
MARCH
The Gas Act 1995 comes into force. British Gas transfers certain assets including its supply business, renamed British Gas Trading (BGT), in accordance with the requirements of the Gas Act 1995.
Transco’s Network Code officially comes into effect. The Network Code is a legal framework to define the rights and the responsibilities of BG Transco and the other participants in the gas industry.
DTl’s Gas and Oil Measurement Branch (GOMB) joins Ofgas to become its Technical Directorate.
APRIL
The national roll-out of competition in the domestic supply market begins with the introduction of competition in the first pilot phase in the south-west of England.
MAY
Ofgas publishes its initial proposals for the 1997 Transco price control.
JUNE
Initial proposals for the 1997 price control for British Gas Trading’s domestic supply business are published by Ofgas.
JULY
Ofgas announces that Transco will be required to make available its database of meter point numbers (M-numbers) to any licensed gas shipper or supplier requesting the information.
The requirement on British Gas to publish price schedules in the industrial market for firm gas is permanently lifted by Ofgas.
(QHUJ\,QWHUQDWLRQDO,QF 88 %59 AUGUST
Ofgas publishes its final proposals for Transco’s transportation and storage price control covering the period 1997-2002. The proposals, if accepted, could lead to a cut in the average domestic gas bill of almost f30 a year in 1997, rising to over f50 in 2001.
SEPTEMBER
An Ofgas consultation document proposes extending domestic competition to 1.5 million customers in Dorset, the former county of Avon, Kent, and Sussex.
OCTOBER
British Gas Transco rejects the proposals by the Office of Gas Supply (OFGAS) for its price control, prompting a referral to the MMG. Gas begins to flow through the Scotland-Northern Ireland Pipeline (SNIP) interconnector.
Following BG Transco’s rejection of Ofgas’ final price control proposals, Ofgas refers the company to the MMC.
NOVEMBER
Ofgas reaches an agreement with British Gas Trading on domestic price controls covering the period 1997-2002. As a result the average domestic gas bill would be cut by £7 in 1997/8 with further reductions thereafter.
DECEMBER
British Gas outlines its proposals for the demerger of the supply business.
Following complaints about doorstep selling by Eastern Natural Gas, the company signs a new voluntary code of conduct to cover this method of selling.
A Mori poll commissioned by Ofgas found that in the first phase of competition (Cornwall, Somerset and Devon), 66% of people surveyed thought that competition was a good idea.
Ofgas announces its final decision on the dates for the start of the second phase of competition; February 10 for Dorset and Avon and March 7 for Kent and Sussex.
Mr Douglas McIldoon is appointed as the first DG for Northern Ireland.
FEBRUARY
British Gas Trading (BGT) and other assets are demerged from British Gas as Centrica. The remaining parts of British Gas are renamed BG plc, and TransCo is renamed Transco. Shares in Centrica and BG plc begin trading. BG plc owns and operates the gas pipeline and storage system in Great Britain through Transco and BG storage which is regulated by Ofgas. BG plc also runs exploration and production businesses.
The second phase of the pilot scheme for domestic competition begins in Dorset and Avon.
Ofgas investigates British Gas Trading’s selective price cuts for its direct debit customers in the Phase I area of competition to determine if they are anti-competitive,
(QHUJ\,QWHUQDWLRQDO,QF 89 %59 President of the Board of Trade, Ian Lang, announces the roll-out of competition throughout the remainder of Great Britain. This will begin in Scotland and North East England and move southwards in six stages. The positive starting date is advanced from April 1998 to October 1997.
MAY
Ofgas publishes a consultation document concerning revisions to the Balancing Regime. The document follows a two month joint review by Ofgas and Transco which found that:
the balancing regime physically worked;
• Prices were sometimes volatile and did not always reflect the actual supply and demand position;
• Shippers didn’t always have an incentive to balance; and
• Costs to the system are not properly targeted.
JUNE
The MMC publishes its report into BG plc’s pricing of gas transportation and storage services.
Ofgas accepts MMC report on BG Transco’s price control which largely supported Ofgas’ proposals and recommended that:
• There be an initial cut of 21 per cent in Transco’s charges; and
• Prices be further reduced by RPI-2 for the subsequent years of the control period.
Ofgas publishes a consultation document detailing proposals for the final stages in the roll-out of competition in the domestic gas market throughout Great Britain. The document proposes beginning the next stage in Scotiand and North East England on November 1, after which competition will move southwards, beginning early 1998.
Ofgas issues a consultation paper on British Gas Trading’s Goldfish Credit Card. The main concern is that the card might give BG an unfair advantage.
A set of 13 factsheets is published by Ofgas, answering in detail the most frequently asked questions about gas competition.
JULY
Following the MMC report of the previous month, Ofgas publishes detailed price control proposals for Transco. The report recommends separate charging conditions for the transportation and storage of gas and a 21 per cent reduction in Transco’s charges in the first year followed by a price cap of RPI-2 per cent for the remaining four years of the control. This would be subject to the adjustment for under-recovery of revenues from the previous period.
Ofgas launches a public awareness campaign to inform everyone on mains gas of the benefits of competition. Press and radio advertising, factsheets and leaflets are to be used as well as a specially created freephone helpline.
AUGUST
Ofgas investigates BG’s proposed new tariffs to determine if they would discriminate unduly against certain customers and contravene the Ofgas price control tariff caps.
(QHUJ\,QWHUQDWLRQDO,QF 90 %59 Ofgas publishes a consultation document on action to be taken in the event that a supplier or shipper of gas goes out of business.
Ofgas confirms that gas competition will be coming to Scotland and the North East of England on November 1.
SEPTEMBER
Ofgas announces that it has modified British GasTrading’s licence to require the company to give Ofgas advance notice of changes it intends to make to the prices it charges in areas where competition is already established.
Ofgas announces the imminent publication of a consultation document asking suppliers and customers for their views on British Gas Trading’s extension of Value Plus tariff in the Phase 2 areas of domestic competition. Responses will be sought on whether:
• Competition is established in the Phase 2 area;
o ValuePlus constitutes predatory pricing; and
o ValuePlus will pre-empt the establishment of competition in other part of Great Britain.
Competition reaches the half million mark as roughly one in four people on mains gas, in areas already open to competition, switch suppliers.
OCTOBER
Transco’s storage activities are established as a separate stand-alone business within BG plc, to be known as BG Storage.
Ofgas puts in place a new price control over BG Transco’s transportation and storage services (1997-2002) which includes the modifications proposed by the Mergers and Monopolies Commission (MMC).
In a move aimed at rooting out misleading sales practices in the expanding domestic gas market, Ofgas publishes a proposed licence condition on marketing. This would mean licensed gas companies could be penalised by Ofgas if their sales personnel give misleading or deliberately inaccurate information to prospective customers.
Ofgas sets out its ruling on concerns about anti-competitiveness and undue discrimination issues arising from British Gas Trading’s involvement with the Goldfish credit card. There will be no problem with the card remaining in the market place as long as British Gas customers are to be made aware that they can redeem Goldfish points against their final BGT account if they wish to change to an alternative supplier.
Ofgas submits a paper to the Government’s Review of Utility Regulation.
NOVEMBER
Phase 3 of the opening of the domestic market to competition started on November 1 in Scotland and North East England. More than 400,000 customers have already signed up out of a market of around 2.5 million households on mains gas.
Offer and Ofgas issue a joint consultation paper on dual fuel offers in the electricity and gas markets.
(QHUJ\,QWHUQDWLRQDO,QF 91 %59 DECEMBER
The Department of Trade and Industry (DTI) announces a review of energy sources for power generation and plans a moratorium on Section 36 consents for new power projects until completion of the review. The European Council of Energy Ministers agrees a common position on the Single Market for the Natural Gas Directive.
JANUARY
Ofgas and BGT announce new lower tariffs for gas customers with prepayment meters.
A new marketing licence condition which will enable Ofgas to act against companies which mislead consumers or use improper sales methods is announced . The condition will enable Ofgas to penalise companies whose personnel give misleading or deliberately inaccurate to prospective customers.
Ofgas and Offer ask the Public Electricity Suppliers (PES) and BGT to stop Dual Fuel offers covering gas and electricity in areas where the respective supply markets are not open to competition.
FEBRUARY
The final stage of domestic gas competition is announced, which will enable around 20 million households to choose their gas supplier. Competition will be complete by May 23 1998, a month earlier than scheduled.
Over a million customers have switched to a new domestic supplier in the competitive domestic gas market. This means that almost one in four people have switched in areas already open to competition.
Ofgas launches an investigation into Northern Electric, after receiving information alleging incorrect training and the use of misleading door step sales techniques by a sales company acting on behalf of Northern Electric. The action comes three weeks after the introduction of a new gas marketing condition to the gas suppliers’ licence.
MARCH
The government publishes its Green Paper on utility regulation.
Ofgas issues a provisional order requiring Northern Electric to act immediately to overhaul its doorstep selling procedures.
Competition in gas meters gets underway. The first competitive meter removal is completed by Gas West Ltd. Previously, Transco held the monopoly.
Ofgas conducts an investigation into the doorstep sales techniques of Eastern Natural Gas (retail) Ltd, following information suggesting a breach of the new Standard Licence Conditions.
The latest Mori Report confirms that 83 per cent of householders in Phase 2b of gas competition (Kent, East and West Sussex) who had switched to a new supplier had been contacted on the doorstep. The survey found that people who change their gas supplier find doorstep selling useful and informative.
APRIL
Ofgas initiates a review of storage services. (QHUJ\,QWHUQDWLRQDO,QF 92 %59 More than 1.5 million people have chosen to switch to a new gas supplier in the newly competitive domestic market.
MAY
Liberalisation of the domestic supply market is completed as the domestic market fully opens on May23.Two million people throughout Great Britain switch to different gas suppliers.
Eastern Natural Gas is cleared of the allegations concerning their sales techniques.
An Ofgas and Offer joint paper, Regulatory Issues Associated with Multi-Utilities, says that customers could benefit from companies that supply more than one utility service.
JUNE
Preliminary conclusions of the government’s review of energy sources for power generation are announced.
The European Parliament and the European Council adopt the Single Market for Natural Gas Directive.
Ofgas publishes its response to the government Green Paper on utility regulation.
Offer and Ofgas, publish their industry-wide action plans to ensure efficiency, choice and fairness in the provision of gas and electricity to disadvantaged customers.
JULY
Ofgas publishes proposals on the way it would like to see a competitive market develop in the storage of gas. The document sets out six measures which would help to ensure effective competition in storage.
Ofgas investigates potential anti-competitive practice in the Industrial and Commercial gas market. Some Industrial and Commercial customers have had their application to move to a new supplier vetoed by their existing supplier.
Following an Ofgas investigation, British Gas Trading (BGT) abolishes the premium on more than a million customers who pay for their gas using a pre-payment meter. The reduction of almost 3% will bring them in line with BGT customers who use credit meters and pay their bills through the company’s standard credit tariff.
AUGUST
The Single Market for Natural Gas Directive enters into force.
More than 3 million households have now taken the opportunity to switch to a new gas company. This represents more than 15% of the total domestic market of around 20 million domestic customers.
SEPTEMBER
The appointment of Mr Callum McCarthy as the next Director General and Director General of Electricity Supply is announced. He is to be the first energy regulator for Great Britain, subject to legislation to amalgamate the regulatory regimes for gas and electricity.
OFGAS and BG plc reach agreement to auction storage capacity at the Hornsea and Rough gas storage facilities. (QHUJ\,QWHUQDWLRQDO,QF 93 %59 Competition in gas meter removals for all suppliers is introduced by the Regulator. Until now, the pipeline operator, Transco, has been the only company to remove gas meters.
Ofgas announces its serious concern that the terms of the sale by BGT of its Central Quantum Office (CQO) to a meter manufacturer will harm the development of competition for prepayment customers.
It is announced that an independent on-the day commodity market (OCM) to enable the pipeline company, Transco, and gas shippers to buy and sell gas to balance supply and demand should be in operation in October 1999.
Following an agreement between Ofgas and BG plc on the auction of BG Storage’s natural gas storage capacity, the storage of gas will change from a monopoly to a competitive business. The auctioning of storage rights in the Rough and Hornsea facilities will be completed by May 1999.
OCTOBER
The DTI publishes the conclusions of the government’s review of energy sources for power generation.
Mr John Battle, Minister for Energy and Industry, publishes a consultation document in which he details the proposed reforms to the regulation of electricity and gas.
The Bacton-Zeebrugge Interconnector linking the national transmission system (NTS) with the European gas grids is opened.
Ofgas publishes proposals which are expected to open up gas metering and meter reading to competition, leading to improved services to domestic customers.
A review of competition in the domestic gas market is published. Ofgas states that competition in gas supply will continue to grow providing BGT does not take unfair advantage of its dominant position.
NOVEMBER
A MORI report published by Ofgas finds that low income consumers in the D and E social groups are taking full advantage of gas competition and are therefore not being excluded from the competitive market.
DECEMBER
Mr Douglas McIldoon, Director General Northern Island, is re-appointed to the post for a second term
Ofgas announces new arrangements for the auctioning and trading of gas storage, starting in 1999. These arrangements, for auctions of capacity in BG’s Rough and Hornsea gas storage facilities, will replace the present system where prices are regulated.
JANUARY
Callum McCarthy becomes the Director General of Electricity and Gas Supply, succeeding the previous Director General, Clare Spottiswood.
(QHUJ\,QWHUQDWLRQDO,QF 94 %59 Following an investigation into complaints alleging anti-competitive activity by Transco in relation to connections, Ofgas publishes proposals to impose an enforcement order on Transco to make it tighten up the way it operates its connections business.
FEBRUARY
Ofgas imposes an enforcement order on Transco to tighten up the way it operates its connections activities.
Competition is introduced into gas storage. A landmark agreement, which is expected to lead to lower gas prices in winter, when gas is used most, is reached between Ofgas and BG Storage.
MARCH
Ofgas publishes proposals for reform of gas trading arrangements (RGTA). These included a new on the day trading regime for buying and selling wholesale gas to be run by an independent market operator and open to Transco, gas shippers and suppliers.
A new corporate structure and a new location for the combined electricity and gas regulatory office is announced by Ofgas. The decisions follow widespread consultation on the work that the new organisation is expected to do over the next five years.
Ofgas publishes a progress report on the gas pipeline constraints at Scotland’s St Fergus terminal, which led to additional costs of £21 million last year. Constraints meant gas shippers were unable to flow gas through St Fergus into the national pipeline system. At the same time, at the Bacon terminal in Norfolk, there was a shortage of gas flowing into the system, which led to additional costs of £2 million.
APRIL
The MMC is replaced by the Competition Commission. The auctions of short- and long-term capacity at Rough and of short term capacity at Hornsea take place.
MAY
The National Audit Office (NAO) publishes its report on the introduction of competition in the domestic market. Since it was written, the number of people choosing to change their domestic gas supplier has jumped from around 4 million to 4.5 million. This total is documented as rising at the rate of 5,000 households a day.
OFFER and Ofgas publish a discussion document asking for ideas to help the fuel poor. Responses to the document will help shape the office’s Social Action Plan.
Details of new gas trading arrangements for Great Britain, that will more realistically reflect the costs of balancing supply and demand in the national pipeline system, are released. The reforms will be introduced on 1 October 1999.
Great Britain becomes the first country in the world to offer all 26 million electricity and gas customers - industrial, commercial and domestic - the choice of which company supplies their energy.
JUNE
The regulator publishes a preliminary consultation document looking at the options for a review of the new price controls for British Gas Trading (BGT), a subsidiary of Centrica plc, the dominant gas supplier to the domestic market. The current control expires on 31 March 2000.
(QHUJ\,QWHUQDWLRQDO,QF 95 %59 The Office of Electricity Regulation (OFFER) and OFGAS begin to operate as the Office of Gas and Electricity Markets (OFGEM).
BG plc announces proposals for a group restructuring.
AUGUST
OFGEM publishes a consultation document on BG plc’s proposed restructuring.
SEPTEMBER
A decision document on the NGTA is published by OFGEM. Auctions of National Transmission System (NTS) system entry capacity take place ahead of the October introduction of the NGTA.
Following the launch of a Fundamental Review of Gas Safety by the Health and Safety Executive (HSE), the HSE issued a consultation document outlining the proposed amendments to “The Gas Safety (Management) Regulations (GS(M)R)”.
OCTOBER
The New Gas Trading Arrangement (NGT) begins to be introduced.
NOVEMBER
The Government announces a Utilities Bill to provide a new framework for the regulation of the gas and electricity markets to provide a fair deal for customers.
(QHUJ\,QWHUQDWLRQDO,QF 96 %59