Study on Regulation of Tariffs and Quality of the Gas Distribution Service in the Energy Community

Transcription

1 Study on Regulation of Tariffs and Quality of the Gas Distribution Service in the Energy Community Gas KEMA Consulting GmbH August This report was financed by the Energy Community.

2 Study on Regulation of Tariffs and Quality of the Gas Distribution Service in the Energy Community. Final Report. KEMA Consulting GmbH, Kurt-Schumacher-Str. 8, D Bonn Bonn, 05 August 2010 Experience you can trust

3 Contents 1. Introduction Theory of Gas Tariff Methodologies and Regulations Tariff Regulation Why Regulation Areas of Regulation Reasons and Options for Unbundling Regulatory Regimes Revenue Requirements Tariff Setting Pricing Objectives Cost Allocation Customer Category Definition Distribution Tariffs Supply Tariffs Quality Regulation Overview Security of Supply Technical Quality and Safety Quality of Service and Reliability Vulnerable Customers Definition of Vulnerability for this Report Treatment of Vulnerable Customers Supporting Mechanisms Issues for Regulators General overview on EU gas tariff methodologies and regulations EU Legislation Tariff Regulation Tariff Methodologies and Levels Tariffs and Competition Tariffs and Efficiency Tariffs and Investment EU Quality Regulation EU Measures to protect Vulnerable Customers Study on Regulation of Tariffs and Quality of the August 2010 Gas Distribution Service in the Energy Community Page i

4 Contents 4. Gas Tariff Methodologies and Regulations in the Energy Community Contracting Parties and Observer Countries Gas markets in the Energy Community Regulation Distribution tariffs including connection (methodology, levels) End-user tariffs (methodology, levels) Quality of supply Vulnerable customers Recommendations Annex A: Case Studies A.1 Slovenia A.2 Romania A.3 Portugal Annex B: Questionnaire Annex C: Answers received from participating regulators Study on Regulation of Tariffs and Quality of the August 2010 Gas Distribution Service in the Energy Community Page ii

5 Figures Figure 1: Areas of Regulation Gas... 4 Figure 2: Examples of Quality Incentive Schemes Figure 3: Graphical representation of a rising block system Figure 4: EU legislation for gas Figure 5: Regulators participating in the questionnaire and analysed for this report Figure 6: The Slovenian gas network Figure 7: Natural gas transport routes to Slovenia Figure 8: Number of new customers connected to the distribution network in Figure 9: The Romanian gas network Figure 10: Evolution of gas tariffs in Lei / 1000 m³ Figure 11: The Portuguese gas network Figure 12: End-user regulated tariffs Figure 13: Average price of end-user tariffs ( ) Figure 14: Structure of the average price of end-user tariffs ( ) Study on Regulation of Tariffs and Quality of the August 2010 Gas Distribution Service in the Energy Community Page iii

6 Tables Table 1: Regulation of gas end-user prices in EU member states in Table 2: Gas distribution tariffs in EU member states in Table 3: Average gas supply tariffs for household customers in EU member states (in Euro/GJ) Table 4: Average gas supply tariffs for industrial customers in EU member states (in Euro/GJ) Table 5: Unbundling of gas DSOs in EU member states in Table 6: Reported number of interruptions per 100 customers in UK Table 7: Customer satisfaction repairs of unplanned interruption UK Table 8: Customer satisfaction planned interruption / replacements UK Table 9: Guaranteed Standards of Performance / Penalty payments UK Table 10: Countries with specific support system for gas consumers Table 11: Customer Categories that are included in a support system Table 12: Overview on the natural gas sectors Table 13: Overview on the natural gas consumption Table 14: Regulation in the natural gas market Table 15: Determination of tariff methodologies, structures and levels Table 16: Regulatory regimes Table 17: Unbundling and benchmarking Table 18: Elements of distribution tariffs Table 19: Costs included in the cost base of distribution tariffs Table 20: Distribution tariff levels in Table 21: Standard connection charges Table 22: Elements of end-user tariffs Table 23: Average end-user tariff levels for household and industrial customers without taxes in /Joule Table 24: Shares of commodity, transmission, distribution, end-user supply, taxes and VAT and other elements in end-user tariffs Table 25: Automatic adjustment mechanisms for end-user prices and end-user categories 76 Table 26: Customer choice Table 27: Application of quality of supply regulation Study on Regulation of Tariffs and Quality of the August 2010 Gas Distribution Service in the Energy Community Page iv

7 Tables Table 28: Quality indicators included in the regulation of commercial quality Table 29: Quality indicators included in the regulation of gas safety Table 30: Quality indicators included in the regulation of reliability Table 31: Quality indicators included in the regulation of technical quality Table 32: Indicators of commercial quality Table 33: Definition of vulnerable customers Table 34: Support mechanisms for vulnerable customers Table 35: Consequences if vulnerable customer can / does not pay its bill Table 36: Average frequency of meter readings and invoicing and the collection rate Table 37: Standard customer groups in Slovenia Table 38: Quality of supply in the distribution network (gas year ) Study on Regulation of Tariffs and Quality of the August 2010 Gas Distribution Service in the Energy Community Page v

8 1. Introduction This study has been prepared by KEMA on behalf of the Energy Community (EC), Vienna. The Energy Community extends the EU internal energy market to South East Europe and beyond on the grounds of a legally binding framework. It thereby provides a stable investment environment based on the rule of law, and ties the Contracting Parties together with the European Union. The overall objective of this report is to provide an overview of natural gas pricing issues (distribution and retail) in the EC member states and compare them with the European best practice. It analyses tariff levels, tariff and quality regulations and specific treatments for vulnerable customers currently applied in the gas distribution and gas supply markets in the Energy Community Contracting Parties (Albania, Bosnia and Herzegovina, Croatia, FYR of Macedonia, Moldova 1, Montenegro, Serbia, UNMIK 2 ) and three Observer Countries (Georgia, Turkey, Ukraine). Within this report KEMA assesses the developments and regulations of the local gas markets of the Contracting Parties and Observer Countries against each other and in comparison to the natural gas markets of the European Union. Furthermore this report provides recommendations and preliminary proposals on how the current conditions and regulations can be further improved and brought in line with the best practices in the European Union. This should enable regulators in the Energy Community to evaluate and adopt the gas distribution and supply tariff structures and the quality measures necessary for a secure, efficient, competitive and affordable energy supply. As part of this project KEMA has developed a detailed questionnaire, which was sent out to the regulators in the Contracting Parties and Observer Countries of the Energy Community in December In addition the questionnaire was also sent to the regulators in Austria and Slovenia. Completed questionnaires have been received from 12 jurisdictions. Given the constitutional structure of Bosnia and Herzegovina, results for the Federation BiH and the Republika Srpska of Bosnia and Herzegovina 1 Moldova signed the declaration for joining the Energy Community on 17 March After ratification of the protocol Moldova is treated as Contracting Party as of 1 May Pursuant to the United Nations Security Council Resolution Gas Distribution Service in the Energy Community Page 1

9 are displayed separately in this report. In addition further data has been taken into account from a number of national and international sources. 3 This report has been structured into 3 main sections, describing and analysing the general theory (section 2), the European best practice (section 3) and the current situation in the Energy Community Contracting Parties and Observer Countries (section 4) of natural gas markets tariff methodologies and regulations. Section 4 presents preliminary proposals on how the current natural gas systems and regulations in the jurisdictions of the Energy Community can be further improved. Annex A gives three detailed case studies on the current tariff methodologies and regulations in the natural gas markets of Slovenia, Romania and Portugal. Annex B shows the questionnaire that has been sent out to the participating regulators and Annex C lists all answers to the questionnaire in detail. 2. Theory of Gas Tariff Methodologies and Regulations 2.1 Tariff Regulation This section presents fundamental background information on tariff regulation and introduces the rationale of regulation and the particular specifications in the area of natural gas Why Regulation The introduction of economic regulation is driven by the need to control the activities of monopolistic structures which are essential for the development of competition and the protection of consumer interests in other (linked up- and downstream) markets. Gas (and electricity) transmission and distribution networks are considered as such essential facilities and natural monopolies. 3 Additional sources include: Energy Community (2008): National Reports for Albania, Bosnia and Herzegovina, Croatia, UNMIK, FYR of Macedonia, Montenegro and Serbia; Annual Reports of the regulators; Energy Information Administration; Eurostat, DG TREN; ERGEG; ENTSO-G, Energy Community Regulatory Board (2009): Vulnerable Household Customers an ECRB Contribution to a Common Understanding, Gas Distribution Service in the Energy Community Page 2

10 The major regulatory objectives are to: ensure equal and non-discriminatory access to essential facilities for all sector participants with a view to establishing and improving the conditions for competition in the gas (and electricity) sectors protect consumer interests and eliminate monopoly inefficiency ensure financial viability of industry participants by allowing them to recover their efficient costs. For example in a situation where only one company operates in a market, the market price cannot be considered as exogenous to this company. Realistically, this company would recognise its monopoly position and its influence over the market price by choosing that level of price and output that maximised its overall profits. Of course, it cannot choose price and output independently, as for any given price, the company will be able to sell only what the market will bear. If the company sets a very high price it will be only likely to sell a small quantity as the consumers will react negatively to the price increase. Generally, if effective competition exists then there is no need for regulation. However, where competition is not possible (like in the case of natural monopoly), economic regulation is required to prevent the abuse of market power by dominant or monopolistic industry participants. Natural monopolies arise if duplication of an infrastructure or service is un-economic, i.e. the character of technology and demand dictate that the costs of construction do not make duplication of the network infrastructure economically feasible. The underlying source of this problem is the so-called sub-additivity of costs. The main sources of sub-additivity of costs are economies of scale and economies of scope. Economies of scale imply that average costs fall with increasing output. The most prevalent source of economies of scale is fixed costs, costs that are incurred irrespective of the level of output. Economies of scope arise if a given quantity of each of two or more goods can be produced by one firm at lower costs than if each good were produced separately Areas of Regulation In the area of gas, the need for regulation of certain services depends on the economic properties of the services and (wholesale and retail) market arrangements. The following figure shows the different areas in the gas sector. The figure presents Gas Distribution Service in the Energy Community Page 3

11 gas activities categorised into areas that are subject to regulation, competitive services and where competitive potential exists. Each area is explained in the subsequent chapters. Figure 1: Areas of Regulation Gas Gas Production / Import Gas Storage Anciliary System Services Gas Transmission / System operation Gas Wholesale Supply Gas Distribution Gas Retail Supply Metering and Billing Services subject to regulatory control Competitive services Services where competitive potentials exist Gas Production / Import The small number of indigenous resources, the strong dependence on external supply sources and the heavy economies of scale in the upstream business have resulted in a limited number of competitors in the field of gas production. Gas production is limited to geographical areas where gas is naturally available. The costs of production facilities are high and can strongly differ depending on the gas source and its technical accessibility. The high investment costs of production (including the risk of exploration before a gas source is developed) are traditionally recovered by longterm supply contracts. Natural gas production is considered as a competitive business area. Regulations in the area of production should therefore focus on health, safety and environmental aspects only. To make competition work on up-stream natural gas production it is essential that gas production companies are effectively unbundled from natural gas transmission and distribution services Storage Services Gas storage can be used to support the reliable operation of the network, but also as a source of energy supply, e.g. to balance seasonal demand differences. There are different types of storages and their investment cost depends on the construction technology and location. The biggest storages are constructed under- Gas Distribution Service in the Energy Community Page 4

12 ground, e.g. in former salt caverns or exhausted oil and gas fields or aquifers (porespace storage). The feasibility of constructing such storage facilities and the associated construction cost heavily depend on geological conditions. In principle, gas storage services can be exposed to competition, therefore they are classified as a service where competitive potential exists. Economies of scale are not as high as in gas networks (discussed below). Gas storage may have significant variable costs including compressor costs, liquefaction and re-gasification costs, losses in case of LNG storage, cushion gas, etc. Cost sub-additivity is not fulfilled for storage services. Storage is thus not a natural monopoly. Nevertheless, storage operators often hold a de facto monopoly. 4 Big underground storage facilities in particular can only be constructed where adequate geographical conditions exist. Moreover, they can usually only be reached via one single network. In other words, competitive gas storage service can only be provided if: Several storages exist A sufficient number of storage facilities are equally accessible 5 : Technical access is possible Storage access conditions and network access conditions are transparent and non-discriminatory Storage and network capacities are available. In all cases where these conditions are not fulfilled, the storage operator is a potential or de facto monopolist who may be able to exercise market power by charging excessive prices or withholding available capacities in favour of associated companies. In such cases storage tariffs should be subject to regulation. Also, access conditions should be monitored to ensure transparent and non-discriminatory access. The new Gas Directive 2009/73/EC in the 3rd Internal Energy Package leaves the choice of storage regime to the Member States 6. 4 See for example Creti, Anna ed. (2009): The Economics of Natural Gas Storage - A European Perspective, Springer 5 See also: DG Energy (2010), Commission Staff Working Document, Interpretative note on Directive 2009/73/EC concerning common rules for the internal market in natural gas, third-party access to storage facilities, Directive 2009/73/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in natural gas. Gas Distribution Service in the Energy Community Page 5

13 System Services and Ancillary Services Ancillary services are those services procured by transmission system operators which are linked to network operation, such as load balancing, blending and to a certain extent also some storage services. 7 In practice, the network operators usually purchase ancillary services acting as single buyers for such services. If the procurement of ancillary services is carried out competitively there is no need for an ex-ante direct price control. However, the (tender or market) rules and contracts governing the procurement process should be subject to regulatory endorsement and supervision Gas Transmission and Distribution Gas networks are characterised by high initial and irreversible investments that turn into sunk costs if not used. The construction and operation cost of a natural gas system depend on the geographical conditions, the legal requirements (licenses etc.), the distance and the pressure level. Typical asset components of gas transport infrastructure are pipelines, (small / network-related) storage facilities, pressure regulators, compressors (relevant for gas transmission). Theoretically, transmission pipelines could lack the sub-additive cost structure in certain cases so that the natural monopoly character would not be strictly given. However, empirical tests have rarely been carried out so far and those transmission systems which have been tested, evidenced sub-additive cost structures. 8 Irrespective of the academic discussions dealing with the sub-additivity features of gas networks, transmission and distribution pipelines remain regulated in most countries which have undergone a restructuring of their gas markets. LNG transport provides competitive pressure on the long-distance transmission level. LNG transport in general is characterised by rather high cost compared to the cost of pipeline transmission due to the expensive conversion treatment for cooling and re- 7 E.g. in the short term a network operator may need a certain amount of gas for system balancing in case the majority of shippers underestimate demand at the same time. Also, a certain amount of gas offtake capacity is needed in reserve in case the majority of shippers at a given date over-estimated demand. The TSO can achieve these goals by buying (or selling) its gas on the spot market on a day to day procurement basis (if such a market exists), by using longer-term gas procurement with specific flexibility arrangements or by contracting and using storage capacity. 8 Compare Gordon, Daniel V. / Gunsch, K. / Pawluk, C.V. (2003): A natural monopoly in natural gas transmission, in: Energy economics, Volume 25, pp Gas Distribution Service in the Energy Community Page 6

14 gasification. 9 Although both options can be financially compared only for specific projects with clearly observable cost, general estimations indicate that pipeline transport is likely to be less efficient than LNG transport for distances higher than 5000 km. On the contrary, pipeline transport is likely to be more efficient for distances lower than 2500 km Gas Wholesale and Retail Supply Gas wholesale and retail supply are competitive areas. However a functional competitive gas wholesale and retail supply would require: Access to gas pipelines, including both non-discriminatory access rules and pricing as well as available network capacities. Existence of competitive (liquid) gas markets. The first condition (network access) can be enforced and controlled by national regulators, whereas the second one is more difficult due to the prevailing long-term wholesale supply contracts, import dependency and often a lack of liquid short-term markets. The shippers often import on the basis of long-term take-or-pay contracts and pass these contractual relationships through to the retail supply level. The gas industry has always argued that long-term import contracts are fundamental to the EU gas market. Although the role for short-term gas markets has been acknowledged, the gas industry asserted that the gas business in Europe is fundamentally orientated to long-term arrangements, especially given the increased dependency on imports. The main reason is that long-term import contracts limit the risk for investors in gas infrastructure 9 The gas should be first cooled down to temperatures lower than -160 C in a liquefaction station. The produced liquid gas (LNG) is then transported by tanker and delivered to re-gasification terminals. The liquid gas is then converted back to normal gas and injected into the transport pipelines for further transportation. 10 The information is based on the Sector Inquiry of the European Commission, see DG Competition (2007), report on energy sector inquiry (SEC (2006) 1724), 10 January 2007, p The comparison has been made between the costs of pipelines of different throughputs (10, 25, 40 bcm per year) and LNG costs necessary to cover the same throughput. The comparison is based on a number of assumptions, and it is therefore of purely indicative value. Taxes, royalties, efficiency gains, commodity value, extraction costs, production costs, operators mark-up, financing costs have not been considered in the calculation. For pipeline gas, capital expenditure related to laying pipelines on land and building gas compressor stations have been calculated as a function of the distance and on the pipeline s diameter. The main CAPEX cost driver was assumed to be the price of steel (USD35/inch/meter with a price of steel of USD1,250/ton). As regards LNG, the project chosen includes a tanker of 135,000 m³ LNG and a re-gasification terminal with a capacity of 8 bcm per year. All facilities, including the liquefaction plant are assumed to be according to current best technological practice. Gas Distribution Service in the Energy Community Page 7

15 (transit, transmission, storage and LNG) and enhance security of supply. 11 On the other hand, long-term arrangements may decrease the market liquidity and competitive dynamics. Moreover they may also create self-sustaining negative incentives for suppliers to continuously stick to such long-term contracts. The retail suppliers would need a reliable procurement source to cover their gas demand and would prefer the long-term arrangements which may hamper the development of a liquid short-term gas market. As a result, even potentially competitive wholesale and retail gas supply may need to remain under regulatory supervision (through ex-ante price regulation or continuous market performance monitoring) if competition cannot function satisfactorily Metering and Billing Metering and billing can be exposed to competition. Whether or not these services should be under regulatory control depends however on the allowed level of contestability as set out in legislation. If only network operators are entitled to provide metering and billing services, these services will remain regulated. Should the legislation however provide for a competitive provision of these services, i.e. various service providers are allowed to compete; the regulator may decide to abolish the explicit ex-ante price control Reasons and Options for Unbundling Unbundling is fundamental when the energy industry evolves towards more competition. In order to make this competition functional and to ensure that the market is not hindered in its development, the potentially competitive functions should be separated from the monopoly functions. The integration of the businesses poses a risk to competitors and consumers because integrated businesses may attempt to use its status as monopoly service providers to obtain an unfair advantage in the competitive parts of their services. E.g. the integrated businesses may shift costs and charge higher prices for the regulated networks which would favour their competitive services and may hinder the development of competition due to prohibitively high network charges. 11 See DG Competition (2007), report on energy sector inquiry (SEC(2006) 1724), 10 January 2007, p Gas Distribution Service in the Energy Community Page 8

16 In order to promote transparency, to disentangle the interests of network operators from other parts of the vertically integrated company, and to facilitate the tasks of regulators, different unbundling instruments have been designed in the European Union: unbundling of accounts, unbundling into different legal parts and ownership unbundling Accounting Unbundling Accounting unbundling requires natural gas undertakings to keep separate accounts for each of their transmission, distribution, LNG, storage, production and retail activities in their internal accounting. This is to create similar conditions to a situation where activities are carried out by separate undertakings. The firm remains vertically integrated but the costs of the network services and each other business area are kept in separate (non-consolidated) accounts Legal Unbundling Legal unbundling also demands the separation of network activities from the other business areas in a separate company. However network assets still remain under the same ownership as production or retail Ownership Unbundling Under ownership unbundling the company who owns and operates the network assets is fully separated from all other business areas, including the separation of asset ownership. The transmission network operator is not allowed to hold any assets (or shares) in companies operating in the competitive business segments of the gas value chain, while other companies (if not ownership unbundled network operators themselves) are also not allowed to hold any network assets (or shares). Based on their sector inquiry 13 in September 2007, the Commission proposed their third legislative package 14 strongly arguing in favour of ownership unbundling of gas 12 Directive 2009/73/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in natural gas. 13 DG Competition (2007), report on energy sector inquiry (SEC(2006) 1724), 10 January The 3 rd legislative package on EU Electricity and Gas markets consists of Directive 2009/73/EC and Regulation (EC) 715/2009 for the gas and Directive 2009/72/EC and Regulation (EC) No 714/2009 for Gas Distribution Service in the Energy Community Page 9

17 and electricity transmission networks as the preferred regulatory regime of vertical disintegration. However, due to different positions in the EU member states, the new Gas Directive 2009/73/EC includes two alternatives to full ownership unbundling: the creation of an independent system operator or an independent transmission operator Regulatory Regimes A range of forms of tariff regulation are used by regulators, as are various classifications of these forms by commentators. In this report, we discuss the different forms of price regulation under the following categories: Rate of return regulation, referred to sometimes as cost plus regulation; Cap regulation, referred to sometimes as RPI-X or incentive regulation Rate of Return Regulation Under rate of return regulation, the regulator sets prices for the service provider (generally) every one, or sometimes two years, in such a way that they cover the service provider s costs of production and include a rate of return on capital that is sufficient to maintain investors willingness to replace or expand the company s assets. Often the forecast of costs (OPEX and depreciation) are based on the previous year s costs with an adjustment for price inflation. Depending on the regulatory period, rate of return regulation does not normally require forecasts of data for more than one year; it is often applied in situations where it is difficult to obtain reliable data forecasts. This could be because data is difficult to collect or a high degree of uncertainty exists over some key variables, e.g. investment needs or costs due to institutional restructuring. This form of regulation can also be effective in encouraging investments in risky environments if the rate of return regulation is designed to ensure (e.g. through end-of-year adjustments) that the service provider receives a guaranteed rate of return 15. the electricity markets, as well as Regulation (EC) 713/2009 for the establishment of a European regulatory agency. For more details see also section 3.1 of this report. 15 Rate of return regulation is sometimes defined as regulation that guarantees that ex post profits reach certain levels. See Burns P, Estache A, (1999) Infrastructure Concessions, Information Flows and Regulatory Risk, World Bank, Public Policy for the Private Sector, Note No, 203, December Gas Distribution Service in the Energy Community Page 10

18 On the other hand, rate of return regulation has two, well-known and significant disadvantages: It provides little or no incentive to control costs, let alone reduce them. It provides an incentive for the service provider to over-invest in capital equipment and plant. Other disadvantages include the need for frequent regulatory reviews, with often detailed information needs, and hence high associated costs for both the regulator and the service provider Cap Regulation Under cap regulation, prices or revenues are set in advance, usually for a period of three to five years, allowing the company to benefit from any cost savings made during that period. At the end of the period, the prices or revenues are recalculated in order to bring them back into line with costs, and to pass through the benefits of any efficiency gains to customers. The cap refers to the upper limit that is placed on prices or revenue, hence the term price cap or revenue cap. While a few US precursors can be identified, cap regulation was first applied on a large scale to British Telecom in the UK in It is designed to give the service provider a strong incentive to reduce costs. This is partly done by setting the prices or revenues that a service provider can earn over a number of years partially or completely decoupled from the costs it incurs over this time. It is also achieved by allowing the company to keep at least a portion of the benefits of any efficiency improvements over the assumed level of improvements incorporated in the level of the cap for a pre-defined period of time. In order to take account of unpredictable rates of inflation in an economy, a capregulation regime typically allows a firm to vary its prices in any year by an amount linked to the overall level of inflation, as measured by the percentage change in an appropriate price index. This inflation-adjusted price level is then usually adjusted by a percentage, often referred to as the X, that reflects, among other things, the real change to costs that the regulator assumes is reasonable. As explained above, the cap, or upper limit, may be placed on prices, in which case it is often referred to as a price cap, or on revenues, in which case it is referred to as a revenue cap. Gas Distribution Service in the Energy Community Page 11

19 There is no widely accepted classification of the different types of price and revenue cap regulation. Two distinct types of price caps are: Individual price caps, where the regulator sets the upper limit for each individual price. This is the most direct form of price control, but its application is limited to situations where the number of services provided is small and stable and costs are easily identifiable. Tariff baskets, where prices are grouped into one or more baskets on the basis of the services to which they apply. A representative weighted average price for the basket is calculated and an upper limit or cap is then applied to the weighted average price. The service provider faces a cap on this weighted average price, which increases over time on the basis of a RPI-X formula. Advantages of tariff baskets are that in theory the business has an incentive to adopt economically efficient prices and it is consistent with the principle of light-handed regulation. However, in practice the tariff basket is often found to be difficult to understand by market participants and difficult to implement. 16 For the purpose of this report, we divide revenue caps into: Fixed revenue caps, or pure revenue caps as they are sometimes referred to, set an upper revenue limit at the start of the control period as an absolute amount, which is adjusted each year for general price inflation and the X- factor. It is called a fixed cap, because the amount of allowed revenue does not normally vary automatically with a change in volume. Variable revenue caps index the allowed revenues (in addition to inflation and the X-factor) to some measure of change, in one or more other cost drivers, e.g. units distributed or customer numbers or length of network. An advantage of this type of cap is that it allows an automatic adjustment for some changes in costs that are beyond the control of the service provider. 17 One form of cap not covered above is the average (or unit) revenue cap, sometimes also referred to as an average yield cap or revenue yield cap. These are 16 We have observed such difficulties in our work on several projects in Slovenia, Romania and Germany. 17 The term hybrid cap was initially used (in the early 1990s) to describe a hybrid of a revenue and price cap but is now used sometimes to describe a wide variety of forms of revenue cap or average revenue cap with some linkage to demand (i.e. units distributed or sold). Because of the ambiguity over the meaning of the term hybrid cap and to avoid confusion, we generally do not use this term when describing caps. Gas Distribution Service in the Energy Community Page 12

20 sometimes classified as price caps and sometimes as revenue caps. Under an average revenue cap, an upper limit is placed on the average revenue per unit of throughput the business is permitted to earn in any year. The average revenue is then allowed to vary per year on the basis of a RPI-X formula. One of the features of an average revenue cap is that it provides incentives to the regulated business to increase sales, which may or may not be an advantage. Ways of Setting the Caps The most commonly used ways of setting the cap are: 1. Linked caps using building blocks under this approach the regulator first assesses the allowed revenue of the regulated entity for each year of the regulatory period by assessing the revenue components separately for each year, i.e. the OPEX and capital costs including depreciation and return (based on the annual capital expenditures), and incorporating efficiency increase requirements in the revenue projections. The next step is to convert this series of revenues into a cap formula with a starting value that is adjusted each year by an X-factor and inflation. The regulator does this by selecting the starting value and calculating an X so that the present value of the revenues under the cap formula should be the same as the present value of the series of projected revenues. This step is referred to as the smoothing procedure and the resultant X as the smoothing X. 2. Unlinked caps using ex-post efficiency analysis on total costs - under this approach the regulator does not use projections for OPEX and capital costs to arrive at the allowed revenue for the upcoming regulatory period. The allowed revenue is set equal to the actual costs at the end of the previous regulatory period and is adjusted annually by inflation and efficiency increase. The efficiency increase is applied on the total cost reported at the end of the previous regulatory period. Price versus Revenue Caps One basic difference between price and revenue caps is the way they respond to changes in the quantity demanded. Under a price cap, a service provider s revenue will move in the same direction as any change in the quantity demanded, and hence the risk of an unexpected change to demand can be said to lie with the service provider. Under a revenue cap, the level of revenue is guaranteed for the service provider, and hence the risk of a demand change can be said to lie with the customer. Gas Distribution Service in the Energy Community Page 13

21 The appropriateness of the different types of cap will depend partly on how the costs of providing the regulated service change with differences in demand. Assuming for example that the cost structure of a business is such that the average cost per unit sold does not vary with a change in the volume sold. A price cap appears appropriate the business average revenue will not vary with a change in the volume sold and total costs will move in proportion with total revenue. On the other hand, if total costs change only little with differences in demand, then a revenue cap incorporating properly selected cost drivers may be a more appropriate means of price control. However, depending on how the price cap regime is designed, a price cap scheme may encourage the service providers to establish efficient tariffs systems, e.g. using tariff basket caps. Rate of Return versus Cap Regulation The key difference between cap and rate of return regulation is that with the latter, the upper limit on prices or revenue is normally determined directly from actual costs in the previous year. While, in the case of cap regulation, the limit is normally determined from the limit in the previous year. Hence under cap regulation the allowed prices/revenue are determined independently from last year s actual costs and the service provider is able to keep any cost savings that it makes over the period between price reviews and which are above any cost savings assumed, via the X, when the cap is set. The ability to keep these savings is important as it provides the service provider with a strong incentive to make cost savings. Compared to rate of return regulation, cap regulation provides stronger incentives to reduce costs; it can be argued that the longer the time between reviews, the stronger the cost-reduction incentive. Through weakening the relationships between actual costs and regulated prices, cap regulation minimizes many of the deficiencies of rate of return regulation. It avoids the need to review prices annually and can provide greater price stability. However, cost reductions should not be achieved by prohibitive regulatory arrangements that would not allow investors to earn an adequate rate of return. In setting the caps, the regulator will need to ensure that their level is sufficient to cover not only the efficient operation and maintenance costs, but also to provide an adequate return on inherited capital and new investment Revenue Requirements Revenue requirements are equivalent to the justified (eligible) costs that should be allowed to be recovered from the regulated services. Eligible costs should include the Gas Distribution Service in the Energy Community Page 14

22 reasonable efficient OPEX (operation and maintenance cost) and the capital cost (including depreciation and return on assets). The recovery of OPEX does not provide any return to the infrastructure owner, as they are paid out in the form of salaries, ongoing operating and maintenance costs, emergency service costs, etc. These costs allow the business to provide and maintain its service. On the other hand, the inclusion of capital costs in the revenue requirement formula recognises the owner s investment in the regulated company and ensures reasonable return on the efficient assets. This concept of the required revenue is generally expressed through the following formula: RRev t = OPEX t + Depreciation t + RA t Where: RRev t = required revenue (in year t) OPEX t = operation and maintenance costs (in year t) Depreciation t = regulated depreciation (in year t) RA t = return on assets (in year t) 2.2 Tariff Setting Once the revenue requirements of a regulated company have been determined, these are allocated to the service users in the form of a tariff system. Below we explain: the pricing objectives cost allocation issues the tariff strictures components customer category definition distribution network tariffs supply tariffs. Gas Distribution Service in the Energy Community Page 15

23 2.2.1 Pricing Objectives When designing a tariff methodology the following major principles of energy pricing are taken into account: Economic efficiency: An efficient charging structure should signal to users the marginal costs that they impose on the regulated company and encourage the operator to utilise its assets optimally (both day-to-day and in the longer term). Cost recovery: Achieving this objective involves ensuring that price control regulation allows the regulated service provider to recover the operating and maintenance costs and capital costs that are commensurate with the efficient provision of the service. Efficient regulation: Aims to minimise the costs to the service provider of complying with the regulation. It will also take into account the costs to the regulator of administering the regulations. Simplicity and Transparency: It is essential that pricing rules are clearly understood. Regulated charges should be understandable and transparent so that a user can readily determine the charges it faces and respond to them. Furthermore, to avoid disputes the tariff regime needs to be clear and should be based on explicit rules as far as possible. Finally, transparency can be seen as a prerequisite for general acceptance by users and the general public. Non-discrimination: A key element of the pricing regime is the requirement to ensure that a level playing field is created for all service users. This requires the notion of treating all users equally, irrespective of size, ownership or other factors, i.e. nondiscrimination between users unless they generate different underlying cost patterns. In practice, this means that all users should face the same methodology for calculating charges not necessarily the same charges. Social affordability and political acceptance: Microeconomic efficiency principles are not always in accordance with this objective. Introducing cost reflective tariffs often means high price increases for smaller customers. While the computation of cost reflective tariffs is a quantitative effort and depends mainly on the quality of available data and professional knowledge, their implementation for all customer categories cannot be completed overnight. Therefore in order to achieve political acceptability and social affordability, a gradual approach supported by transition arrangements may be required. Macroeconomic constraints: On some occasions, constraints of a macroeconomic nature might play their role in limiting regulators and companies in their actions. Constraints like inflation control, GDP growth requirement, employment policy etc. may Gas Distribution Service in the Energy Community Page 16

24 prevent regulators and companies from pursuing full price readjustment/realignment. On other occasions macroeconomic and microeconomic policies interact to keep price rises moderate, and to make it possible for investors to enter the market without causing widespread malcontent throughout the population. In the next section we discuss the aspects related to achieving policy trade-off. The application of all pricing principles should be considered in the light of their interdependencies and avoid mechanically prioritising one of them. There is no universal answer as to how these principles should be prioritised. Economic efficiency and cost recovery are key objectives in pricing but must be balanced against other objectives. These include non-discrimination against certain market participants, simplicity in implementation and transparency to users, stability to support long-term investment decisions and flexibility to support changing market environments. These objectives represent key criteria for judging the appropriateness of various charges for achieving efficiency and cost recovery objectives Cost Allocation Cost allocation refers to several aspects like the choice of average versus marginal cost pricing, the choice of cost drivers, application of time-of-use tariffs, application of geographically differentiated tariffs etc. With respect to the geographical differentiation the model can be divided into those that provide locational pricing signals and those that do not. The latter are referred to as postal or postage stamp models 18. While models with locational signals (e.g. entry / exit models) have often been used for pricing of gas transmission, postage stamp models are commonly used in the area of gas distribution Marginal versus average cost pricing An important aspect is to decide whether average or marginal cost pricing should be used. The average costs refer to the total costs incurred by the service provider, divided by the number of units of that good or service. This approach is backward looking and aims to distribute the actual costs over the delivered quantities. 18 Presumably the term postal is used to refer to the non-locational nature of stamps, i.e. in most postal systems, the same stamp applies to a particular service regardless of where it is delivered. For example the same stamp would normally apply to posting a parcel of a certain weight, no matter where it is sent within a country. Gas Distribution Service in the Energy Community Page 17

25 The approach of using marginal cost-based prices as signals for efficient utilisation of regulated service attempts to replicate the outcome on the competitive market whereby producers sell at the competitive market price whenever it is equal to or greater than their marginal cost. Marginal costs can be defined as the costs incurred in supplying a small increase in demand of the relevant commodity. Thus, in order to be able to apply the marginal cost concept the increment (kw, m³/day or kwh, m³) must be defined. Depending on whether capital stock is kept constant or investments can be added, marginal (average) cost can be further divided into short and long-run marginal (average) cost. For instance, short run marginal costs are defined as the additional costs arising when one additional kwh is demanded and the installed capacity remains constant. In contrast, long run marginal costs also take into consideration the capital investment incurred by the regulated company when one additional kwh is demanded. Marginal cost (and ideally long run marginal cost) pricing provides signals for efficient resource allocation, but usually does not allow the business concerned to recover costs. Hence in practice, prices are sometimes based on average costs or some mixture of average and marginal costs that provides some of the pricing signal advantages of marginal costs ensures cost recovery. In some instances, the cost allocation model chosen will determine whether marginal or average costs can be used; in others there will be a choice Cost Drivers Yet another issue, generally related to the choice of cost allocation model, is to decide what drivers to use in allocating costs to the chosen tariffs (or charges). This will partially determine the level of the individual charge. The main drivers of gas costs that are taken into account for the pricing 19 are normally the: 1. Capacity required to provide the service to the customers. For the individual customer, this is usually represented by a measure of the customer s peak demand (e.g. MW or m³/day) or, in the case of gas, sometimes reserved capacity. The costs driven mainly by the level of demand are often referred to as the demand 19 There are other drivers of distribution costs, e.g. population density, however, the three listed here are those directly related to actions taken by customers and hence of most use to reflect in the pricing. Gas Distribution Service in the Energy Community Page 18

26 dependent or capacity dependent costs and for a network will include the costs of providing and maintaining the network. 2. Actual usage of energy. The costs driven mainly by the throughput of energy are often referred to as the energy-dependent costs 20 ; 3. Number of customers. The costs driven mainly by the number of customers are often referred to as the customer dependent costs and include for example the cost of reading meters. Sometimes, for example in gas network pricing, a simple ratio can be used to allocate total costs between the demand dependent and energy dependent cost categories. For example, the ratio may be set equal to 50:50, normally meaning that 50% of total costs are allocated to the demand dependent category of costs and 50% to the energy dependent category. The ratio chosen is sometimes intended to represent the actual ratio between fixed and variable costs or result from application of marginal cost pricing; other times it also takes into account such things as the impact on smaller customers 21. In gas pricing, the ratio between demand and energy-dependent costs is often referred to as the capacity/commodity split Pressure Tier / Consumption Zones Gas customers are normally categorised by annual consumption or pressure tier of connection. Pressure tier may provide a reasonable proxy for cost of utilisation, however it has the disadvantage that it may encourage bypass of the low pressure systems to avoid the high charges for using this part of the network. While this could encourage better pricing that aligns the network cost structure, incentives to connect to higher pressure levels would leave network capacity under-utilised and cause a price increase on lower pressure levels. This could particularly be the case for countries with developing gas markets, where a small number of industrial customers account 20 Some costs, such as that of system operation do not vary with the throughput of energy, but they may be included in the energy dependent costs for the purpose of allocating costs to tariffs. Such costs also do not vary with demand, customer numbers or other customer characteristics, and it may be held that a non-discriminatory way of allocating these costs among consumers is to divide them by the energy transported. 21 Smaller customers tend to have lower utilisation of their peak demand than larger customers and so they are generally hit relatively harder by a tariff structure where a high proportion of costs is allocated, via the demand dependent cost category, to the demand charge. Hence the proportion of total costs allocated to the demand dependent category may be reduced to lower the impact on smaller customers, particularly those with a low level of energy consumption. Gas Distribution Service in the Energy Community Page 19