Commission s Proposals on Distribution Use of System Revenue Requirement and Tariff Structure 1 October September 2007

Transcription

1 Commission s Proposals on Distribution Use of System Revenue Requirement and Tariff Structure 1 October September 2007 June 2003 CER/03/143

2 TABLE OF CONTENTS 1. INTRODUCTION BACKGROUND The Determination of Allowable Revenues Duration and Form of Revenue Control BGD s Operating Costs BGD s Assets and Investment Programme Depreciation Costs Return on Assets (BGD s Cost of Capital) Allowable Revenues Revenue Control Formula Structure of Distribution Tariffs... 23

3 1. INTRODUCTION Under the Gas (Interim) (Regulation) Act, 2002, the Commission for Energy Regulation ( the Commission ) is responsible for regulating charges in the natural gas market. This includes the functions of gas transmission, distribution and supply to final customers. In carrying out this function, the Commission is required to: 1. Secure the continuity, security and quality of supplies of natural gas; 2. Secure that there is sufficient capacity in the natural gas system to enable reasonable expectations of demand to be met; 3. Promote competition in the supply of natural gas; 4. Act in a non-discriminatory manner, such that the Commission does not discriminate unfairly between holders of licences, consents and Bord Gáis Éireann (BGÉ); 5. Protect the interests of final customers of gas. This document sets out the Commission s proposal on the determination of revenues for BGÉ s distribution business (BGD) during the period from 1 October 2003 to 30 September The Commission will consult separately on the determination of BGÉ s transmission revenues. 3

4 2. BACKGROUND On 19 March this year the Commission published a consultation paper entitled Transmission and Distribution Tariffs Objectives and Principles (CER/03/060). That paper initiated the consultation process to determine the level of allowable revenues for the gas transmission and distribution businesses in Ireland. Following the publication of the March consultation paper, the Commission received substantive and detailed written submissions. In response to the level of interest from market participants, the Commission decided that it would be beneficial to hold a public meeting to enable participants to raise questions about the issues raised in the consultation paper and, in particular, review options relating to structure of tariffs as well as the revenue control methodology. A public workshop, held on 15 th May this year, provided the opportunity to discuss issues raised in the consultation paper and allowed industry participants to present their views on different options on revenue and tariff determination. In tandem with the public consultation process, the Commission and its consultants have been involved in a detailed review of BGÉ s costs aimed at formulating a proposed decision on allowable revenues and tariffs for the gas transportation businesses of BGÉ. This consultation paper represents the outcome of that review as it pertains to BGD. A consultation paper on transmission business unit revenues will be published separately, along with papers on distribution and transmission connection policy and tariff methodology. Transmission and Distribution Tariffs Objectives and Principles (CER/03/060) set out the objectives and proposed principles that would guide the Commission s determination of BGÉ s allowable revenues for its transmission and distribution business units. As set out in that paper, irrespective of the specific methodology used to determine revenues and set tariffs, the Commission is keen to ensure that the level of allowed revenue is sufficient to recover prudently incurred operating expenditure and provide a reasonable return on investment, commensurate with the risks faced by BGÉ. Consistent with this principle, the Commission is also keen to ensure that the gas distribution tariff methodology implemented by BGÉ: reflects the costs of serving different categories of customers; provides correct signals for consumption and investment; 4

5 does not discriminate unfairly between different customer categories; and given forecast customer numbers and load, enables BGD to recover no more than the level of maximum revenues allowed by the Commission. In determining the level of allowable revenues for BGÉ s distribution business, the Commission adopted the process used in determining the allowable revenues for the electricity network businesses. This is a methodology that has widespread use amongst monopoly network regulators throughout Europe. The methodology adopted by the Commission has involved the following sequential elements: Step 1 is a detailed and extensive review of the operating costs and network assets of BGD. This has comprised the Commission s engineering, accounting and economic consultants conducting a detailed technical, engineering and economic appraisal of BGD s costs including accounting methodology, assets and future investments and cost allocation methodology. Step 2 is a review of operating costs including network and nonnetwork related costs - against comparator network entities, adjusting for differences including network size and construction, customer numbers and load, amongst different gas distribution entities. Step 3 involves determining the value of the opening asset base; a rate of return on assets commensurate with the risks faced by BGD; and a review of the reasonableness of the future investment programme, given expectations of load, customer growth and market developments. Step 4 entails the determination of an allowable stream of revenues for BGD that are sufficient to cover a prudent level of operating costs and depreciation and which provides a reasonable return on assets and new investments over the regulatory period. Step 5 involves the development of a revenue control formula which provides a transparent and predictable way of determining revenues in each year of the control, depending on customer numbers, demand growth, gas shrinkage and inflation. The formula also provides a mechanism for incentivising BGD to reduce its controllable costs and allows for pass-through of non-controllable costs. 5

6 Step 6 is the determination of the structure of distribution use of system and connection charges depending on the costs imposed by different customers on the system and which yields the level of revenues allowed by the Commission. In reviewing the allowable costs of BGD s distribution activities, the Commission s aim has been to ensure that: BGD s costs are appropriately allocated between regulated and non-regulated activities (including for example, LPG sales and telecommunications ducting assets), to avoid cross-subsidy between these activities; there is adequate separation of activities and costs between BGD and BGÉ s transmission and supply business units; where central costs are shared between various business units within BGÉ, that the principles of cost allocation are an accurate and reasonable reflection of cost drivers; the tariff methodology is transparent, predictable and is easily understood by market participants and customers; tariffs reflect the costs imposed by different users on the system and enable BGD to recover its allowed revenues. The components of these different steps are discussed below. 6

7 3. The Determination of Allowable Revenues 3.1. Duration and Form of Revenue Control Respondents to the Consultation were divided between preferring a relatively short regulatory review period of 2 years and a longer period of 4-5 years. The main arguments for a shorter period were that forthcoming developments in the Irish gas market, particularly in market opening as well as the timing of the development of the Corrib gas field, would make it difficult to predict system demand and, hence, average tariffs. Those who preferred a longer period argued that a reasonable length of time would be required to incentivise BGÉ to make efficiency gains. The Commission has weighed up these two arguments and considers that a four year regulatory period is preferable on the basis that it is a reasonable length of time to incentivise efficiency improvements. The four year review will enable the Commission to implement CPI-X incentive regulation, aimed at achieving operating efficiencies. It will also enable the Commission to monitor the costs and implementation of investments. The responses to Transmission and Distribution Tariffs Objectives and Principles (CER/03/060) suggested widespread support for incentive (CPI-X) regulation. This is the approach that has been used to determine allowable revenues for the electricity network businesses in Ireland. Given this response, and also the success with which this method of regulation has been implemented in regulated network businesses throughout Europe, the Commission has decided to adopt this method for determining BGD s distribution business revenues. In determining BGD s allowable revenues, the Commission has adopted the cash flow methodology used by OFGEM and other regulators. This method discounts operating costs and revenues using an appropriate weighted average cost of capital (WACC) to ensure that, given forecast demand growth and customer connections, the net present value (NPV) of revenues over the review period is equal to the net present value of costs. The different elements of this calculation are discussed below before the calculation itself is presented in the section that follows BGD s Operating Costs The Commission s technical, economic and financial consultants conducted a detailed review of BGD s costs with the view to 7

8 determining the level of prudently incurred costs that BGD would be allowed to recover through tariffs. As part of that process, the consultants were charged with reviewing: the method of allocating operating expenditures between BGÉ s different business units to ensure accurate allocation in respect of cost drivers; the attribution of costs between regulated and non-regulated activities to prevent cross-subsidy between these activities; the scope for efficiency improvements based on a review of the level of BGD s costs relative to its performance and costs and performance of comparator gas utilities operating in other jurisdictions Network Related Operating Costs Network related costs are driven by volume and connected customers. The item covers network operation and maintenance expenditure and excludes overhead costs such as administration, buildings and nonnetwork IT systems. A technical review of network operating costs suggested that these are due to remain relatively constant over the review period. Overall the Commission s engineering consultants were satisfied that these costs were reasonable when benchmarked against comparator entities. Direct operating costs compare favourably with gas companies in other jurisdictions when accounting for the scale of BGE s operations and their portfolio of assets. The principal performance measures used for the comparison of operating costs included: Operating expenditure ( Opex ) per kilometre of distribution network; Leakage costs per kilometre of distribution network; Costs per emergency call; Maintenance cost per installation. However, there was considered to be some scope for reducing some costs, as discussed below: 8

9 New housing sales The Commission believes there is some scope for reducing costs associated with new housing sales on the basis that BGÉ has forecasted a reduction in the number of new houses over the coming four years Gas Shrinkage Costs A review of BGD s gas shrinkage costs suggested that there is some scope for reducing the level of shrinkage on the distribution network. A study undertaken by BGÉ in 2000/01 showed that shrinkage in BGD s network is 2.1% of throughput. The study sought to assess unaccounted for gas (UAFG) in discrete distribution zones. Further analysis of the BGÉ report identified that a figure of 1.9% was more appropriate for shrinkage. On this basis, we have allowed for shrinkage of 1.9% for the whole distribution system Non-network Operating Related Costs Third party claims and insurance An analysis of BGÉ s insurance and third party claims costs revealed these to have increased significantly since 2002, due to the following factors: doubling of BGÉ s asset base, mainly attributable to transmission significant increase in insurance costs increased number (and average amount) of 3 rd party claims. Whilst the Commission accepts that these costs are outside the direct control of BGÉ, we are concerned by the level of these costs. The Commission is therefore proposing to allow BGD a constant real annual amount of 2.9 million a year, i.e. the value of third party claims in 2002/03, and disallowing BGÉ s submission of a 7% a year real increase. The Commission is also proposing a constant real annual amount for insurance, rather than one which increases at 5% a year in real terms. 9

10 Corporate Costs The Commission is proposing no increase in real terms over the period of the review. We are also proposing to disallow 0.65 million a year (or 50%) of public relations costs sought by BGÉ for the transmission and distribution businesses combined. This reduces BGD s public relations cost from 1.3 million a year to 0.65 million a year. The whole of this reduction has been attributed to distribution and is reflected in the overall corporate cost The CER Levy The Commission has adjusted BGD s estimate to reflect the CER s estimate of the levy that will be required over the period to finance the CER s activities in regulating the gas sector. This has the effect of reducing the allowance for this cost from million to million for gas year 2003/ Add New Business Expenditure This item covers BGÉ activities in promoting customer connections in the residential (regulated) market. The Commission considers that a substantial portion of these costs are more appropriately attributable to the gas supply business on the basis that they cover selling activities. On this basis the Commission is proposing that none of the 1.9 million for customer initiation activities be allocated to BGD. However, the Commission is allowing the transfer of 0.8 million of energy supply resources that are currently undertaking network related activities together with call centre costs of 0.5 million and safety advertising of 0.3 million. The level of operating costs that BGÉ submitted for approval is presented in the table below. This is followed by the level of operating costs that the Commission is proposing to allow. All costs are in 2002 prices. 10

11 Table 1 BGÉ Submitted Distribution Operating Expenditures ( 000) Direct Operating Expenditure 2003/ / / /07 Network Maintenance 11,667 11,613 11,757 11,923 Radio Room New Housing Sales 2,107 2,097 2,123 2,153 Technical 1,452 1,445 1,463 1,484 General Management Gas Transportation Development Facilities & Support Costs 2,972 2,959 2,995 3,038 Total Direct Operating Expenditure 20,807 20,711 20,968 21,264 Indirect Operating Expenditure Gas Year 2003/ / / /07 Rates 4,217 4,536 4,770 4,878 3rd Party Claims 3,331 3,873 4,045 4,105 Meter Reading 3,267 2,976 2,977 3,022 Provisions & Billing Direct Shared 11,040 11,608 12,017 12,232 Insurance Premiums 1,925 2,023 2,136 2,247 Other transaction costs 4,120 4,360 4,485 4,563 Corporate costs 2,347 2,401 2,439 2,476 CER Levy 1,233 1,287 1,287 1,126 GPRO & market opening 3,256 4,137 3,527 3,098 Regulatory compliance officer Add new business 8,826 8,755 8,755 8,755 Total Indirect Operating Expenditure 33,165 35,017 35,065 34,763 Gas Shrinkage 2,191 2,464 2,591 2,712 Customer contributions Total Operating Expenditure 55,412 57,442 57,874 57,989 11

12 Table 2 CER Allowed BGÉ Distribution Operating Expenditures ( 000) Operating Expenditure 2003/ / / /07 Network Maintenance 11,667 11,613 11,757 11,923 Radio Room New Housing Sales 1,772 1,831 1,858 1,511 Technical 1,452 1,445 1,463 1,484 General Management Gas Transportation Development Facilities & Support Costs 2,972 2,972 2,972 2,972 Total Direct Operating Expenditure 20,416 20,406 20,618 20,485 Indirect Operating Expenditure Rates 4,217 4,536 4,770 4,878 3rd Party Claims 2,900 2,900 2,900 2,900 Meter Reading 3,267 2,976 2,977 3,022 Provisions & Billing Direct Shared 10,609 10,635 10,873 11,027 Insurance Premiums (Ref note 1) 1,925 1,925 1,925 1,925 Other Trans. Costs (HR, Payroll, Purchasing, etc) 3,813 3,813 3,813 3,813 Corporate Costs 1,973 1,635 1,635 1,635 CER Levy 1,005 1,005 1,005 1,005 GPRO & Market Opening Prog Mgt (Ref note 2) 3,256 4,137 3,527 3,098 Regulatory Compliance Office Add new business 4,550 4,513 4,513 4,186 Overall Total 27,548 28,109 27,709 26,954 Gas Shrinkage Customer contributions Total Operating Expenditure

13 3.3. BGD s Assets and Investment Programme Regulatory Asset Base The Commission and its consultants conducted a detailed review of BGÉ s regulated asset base ( RAB ), and its growth related capital expenditure and its replacement related capital expenditure programme going forward. Following a detailed reconciliation, BGD and the Commission have agreed on an opening asset value of 864 million as at 30 th September, 2003, in 2002 monies. This is BGD s regulatory asset value and currently only includes LPG assets once they are converted to natural gas, and telecommunications ducting equipment. The Commission is however minded to allow LPG assets in the current valuation of the RAB and this will be determined prior to the final decision. The regulatory asset base will be uprated in future in line with a suitably defined eurozone inflation rate, not the Irish CPI. The choice of price index for uprating the asset base should reflect BGD s costs in purchasing equipment and pipework. These costs do not change in line with Irish CPI. Whilst it might be suitable to upgrade operating expenditures with the Irish CPI (as a large component of opex is labour costs which tend to follow CPI), the Commission believes that the eurozone inflation index is more appropriate for uprating the RAB. This is also consistent with the way in which BGÉ s cost of capital has been estimated (see below) Capital Expenditure Programme The table below shows BGÉ s submitted programme for capital expenditure and compares it with the amount that the Commission is proposing to allow during the regulatory period. After the first year of control, the Commission is proposing to reduce BGD s capital expenditure by between 7 million and 8 million a year. Part of the reduction comes from customer contributions from conversion to gas of existing houses and industrial and commercial ( I&C ) connections, in line with the Proposed Gas Distribution Connection Policy, published separately [CER/03/141]. The rest of the reduction occurs in load-related capital expenditure and reflects our engineering consultants analysis that there is scope for reducing 13

14 ongoing growth related capital expenditure by around 5% a year, moving forward, on the basis of increasing efficiencies. Table 4 BGÉ Submitted and CER Allowed Capital Expenditure Programme BGE SUBMITTED 2003/ / / /2007 Growth Related Capital Expenditure Distribution mains 26,497 25,283 26,548 20,609 Service pipes 22,522 22,261 22,959 17,406 Distribution meters 5,111 4,958 4,958 3,874 Market opening & IT costs 4,677 3,587 2,426 1,314 Other 1,925 1,937 2,273 1,679 Total Growth Related Capex 60,732 58,027 59,164 44,881 Replacement Expenditure Mains replacement 6,500 6,546 6,546 4,524 Mains reinforcement 5,153 5,323 3,278 2,597 Service replacement 3,738 3,277 3,277 2,265 Distribution meters Other 1,582 1,937 1, Total Replacement Expenditure 17,736 17,871 14,927 10,459 TOTAL 78,468 75,898 74,091 55,340 CER PROPOSED Growth Related Capital Expenditure Distribution mains 25,172 24,019 25,221 19,578 Service pipes 21,396 21,148 21,811 16,536 Distribution meters 4,855 4,711 4,711 3,680 Market opening & IT costs 4,443 3,408 2,305 1,248 Other 1,829 1,840 2,159 1,595 Total Growth Related Capex 57,695 55,126 56,206 42,637 Replacement Expenditure Mains replacement 6,500 6,546 6,546 4,524 Mains reinforcement 5,153 5,323 3,278 2,597 Service replacement 3,738 3,277 3,277 2,265 Distribution meters Other 1,582 1,937 1, Customer Contributions -5,114-4,346-4,140-4,140 Total Replacement Expenditure 12,622 13,525 10,787 6,319 TOTAL Capex 70,317 68,651 66,993 48,956 Difference between BGE and CER -8,151-7,247-7,098-6,384 14

15 3.4. Depreciation Costs The responses to the consultation indicated general support for a simple, straight-line method of depreciation. The Commission is therefore proposing to adopt this method for depreciating gas distribution assets. The Commission has not proposed any change to the existing economic life of distribution assets Return on Assets (BGD s Cost of Capital) In our March consultation paper on principles, the Commission indicated its preference for using the capital asset pricing methodology (CAPM) in estimating BGÉ s cost of capital. This is the method most widely used by regulators in determining a rate of return commensurate with the risks faced by the regulated utility. Respondents to the consultation also indicated a general preference for using this method on the basis that it is widely used and understood. The table below provides the calculation of BGÉ s WACC. Table 6 BGÉ's Weighted Average Cost of Capital % Calculation 1 Risk free rate (nominal) Inflation Risk free rate (real) 2.5 (1+[1])/(1+[2])-1 4 Debt premium (incl. issuance costs) Cost of debt (real) 3.9 [3] + [4] 6 Equity Risk Premium Tax Asset beta Equity beta 0.9 [8] * (1+[12]) 10 Cost of equity (real, post tax) 7.0 [3]+[9]*[6] 11 Gearing (D/D+E) Leverage (D/E) 1.22 [11]/(1-[11]) 13 Real post-tax WACC 5.0 [11]*[5]*(1-[7])+(1-[11])*[10] 14 Real pre-tax WACC 5.74 [13]/(1-[7]) We have based our estimate of BGÉ s WACC on an asset beta of 0.4. This is in line with estimated betas for British Gas (before Lattice was demerged from British Gas) and Gas Natural (Spain). There are other 15

16 comparators, such as SNAM in Italy and Distrigas in Belgium, whose estimated asset betas are considerably lower than 0.4. But as neither SNAM nor Distrigas has been listed for long, the Commission has not taken these lower estimates into account in arriving at an estimate of BGÉ s cost of equity. We based our estimates of allowable revenues in real terms on a pre-tax cost of capital basis. A full report on the estimation of BGÉ s cost of capital will be available separately on CER s web-site Allowable Revenues Table 7 shows what the Commission s proposals mean in terms of allowable revenues over the period of control. Again, all values are in 2002 prices. As the table shows, the level of allowed revenues that BGÉ will be permitted to recover in 2003/04 amounts to million. This represents a reduction of 2% in real terms, or around 6% in nominal terms, since 2002/03. Moreover, due to an X efficiency factor of 2%, the average distribution tariff will decline by 2% a year, in real terms, in each year of the regulatory period. 16

17 Table 7 Calculation of BGÉ s Distribution Revenue Requirement WACC 5.74% X-factor 2% Use CER proposed opex and capex Yes Yes (values m, 2002/3 terms) 2003/4 2004/5 2005/6 2006/7 Previous under recovery m 4.50 Operating expense m Growth capex m Non-growth capex m Total costs m NPV COSTS m Opening asset value m Depreciation m Investment m Closing asset value m NPV 'RETURN' m TOTAL NPV (return+cost) m CALCULATION OF ANNUAL REVENUES Operating expense m Depreciation m Revenue (*) m Revenue minus (depreciation + opex m NPV Revenue Check m Return on Capital employed 5.2% 5.7% 5.9% 6.3% DEMAND Demand 29,196 31,625 33,698 35,813 Average tariff 4,156 4,073 3,992 3,912 Annual reduction in average tariff -2.00% -2.00% -2.00% (*) Opening revenues are set such that the NPV of revenues = NPV of return + NPV of costs and average tariffs reduce by x% a year Demand GWh 6,673 7,264 7,716 8,130 Peak Day GWh/day

18 4. Revenue Control Formula Distribution costs are largely fixed but also variant with the number of customers connected to the system. For gas distribution systems, costs do not vary with the volume of gas throughput but are dependant on the peak capacity requirements of the connected customers. Given these characteristics, the Commission is considering a revenue control formula, of the type shown below, which allows BGÉ s revenues to rise in line with its costs, which in turn are affected by the number of customers connected to the distribution network. The Commission is also considering implementing performance targets through the revenue control. The formula below is intended to achieve the following: Provide BGD with incentives to reduce controllable costs (i.e. improve efficiency) Incentivise BGD to connect customers to the system by allowing it to recover higher costs if connections are higher than forecast. Incentivise BGD to accurately predict load and customer growth. Whilst the Commission will allow some deviations, the tolerance band will be set between 97% and 103% of revenues. Any over-recovery of revenues beyond 103% will attract an interest rate of Euribor plus 4%. Under and over-recoveries within the tolerance limit will attract a financing rate of Euribor plus 2%. Under-recovery less than 97% will attract Euribor plus 2%. Use a correction factor to allow differences between out-turn and forecast variables to be reflected in BGD s revenue. Provide BGD with incentives to improve its performance (for example, by reducing service interruption) Allow controllable costs to be reduced by an efficiency factor, X%; R t+ 1 t+ 1 = ( 1+ CPIt X ) * ) t + 1 t 2001 [ Bt ( PCt + 1*( FCt + 1 Ct + 1)) + PCDL*( FCDLt + 1 CDLt Pt + 1 ] + Kt K 1 R t+1 is the maximum level of revenues allowed in period t+1 and the revenues on which next years tariffs are based. It is expressed in Euros m. 18

19 CPI t+1 is the annual average CPI for that year. (Forecast figures will be used for year t and t+1). Xt+1 B t+1 is the efficiency factor required for that year, currently set at 2% is the level of allowed revenues in real 2003 prices for the distribution business in year t+1. It is expressed in Euro m as shown in Table A below. P Ct+1 is the value of revenue, which is earned by BGÉ Distribution for each incremental customer connected to the system. The price is shown in year 2003 real in Table A below for each relevant year. FC t+1 is the forecast number of customers connected at the end of year t+1. This forecast is made before the end of year t when determining next year s allowed revenue. C t+1 is the total number of customers connected to the system at the end of year t+1 as set down in Table A, and on which approved base revenues (B t+1 ) were determined. FCDL t+1 is the forecast average number of days lost per connected customer in year t+1. This forecast is made before the end of year t when determining next year s allowed revenue. CDL t+1 is the average number of customer days lost in year t +1 as set down in Table A. P t+1 Any changes in forecast pass-through costs from those included in Bt+1 as available when setting tariffs in year t. This includes, inter alia, changes in Irish offshore and UK rates costs and insurance etc which the CER has indicated will be allowed on a pass-through basis. K t is the correction factor, which ensures that prices in year t+1 are adjusted by an amount equal to the difference between what was actually charged in year t and the forecast of what should have been charged, with interest payments added on. K t-1 is the correction factor which, ensures that prices in year t+1 are adjusted by an amount equal to the difference between the revenues that have already been recovered and what should have been recovered in respect of year t-1, with interest payments added on. 1+ CPIt K t = Rt + ( PCt *( RFCt FCt )) + PCDLt*( RFCDLt FCDLt ) + Pt FRt *(1 + It ) 1 CPIF + t 19

20 R t CPI t CPIF t P Ct RFC t FC t I t FR t P t is the maximum level of revenues allowed in period t and on which this year s tariffs were based. It is expressed in m. is the forecast annual average CPI in the current year. is the annual average CPI, which was forecast for the current year when originally setting this year s allowed revenue. is the value of revenue, which is earned by BGÉ Distribution for each incremental customer connected to the system. The price is as shown in year 2003 real in Table A below converted into nominal values for year t. is the revised forecast number of customers connected at the end of year t. This forecast is before the end of year t. is the forecast number of customers connected to the system at the end of year t. This forecast is made at the end of year t- 1 when determining the allowed revenues for year t. is the average Euribor rate in year t. The Commission will apply a factor of 2% to the under and over-recovery of revenues within the band 97% - 103% of allowed revenues. Any over-recovery above 103% will attract a charge of the Euribor rate +4%. This is the forecast of revenue which will be recovered in year t. This forecast is made before the end of year t. Any changes in forecast pass-through costs from those included in the calculation of R t as available when setting tariffs in year t-1 as available in year t. This includes, inter alia, changes in onshore and UK rates costs and insurance etc which the CER has indicated will be allowed on a passthrough basis. 1+ CPIFt Kt 1 Rt 1 = 1+ CPIAt (1 + I )*(1 + I ) t 1 t P Ct 1 *( AC t 1 RFC ) + P t 1 CDL *( ACDL t 1 RFCDL) + P t 1 t 1 AR t 1 * Rt-1 is the maximum level of revenues allowed in period t-1 and on which last year s tariffs were based. It is expressed in m. 20

21 CPIF t-1 is the forecast annual average CPI in year t-1. This is the forecast made in year t-1 when adjusting the allowed revenue for that year. CPIA t-1 is the actual annual average CPI in year t-1 as published by the Central Statistics Office of Ireland. P Ct-1 is the value of revenue, which is earned by BGÉ Distribution for each incremental customer connected to the system. The price is shown in year 2003 real in Table A below for each relevant year. AC t-1 is the actual number of customers connected at the end of year t-1. RFC t-1 is the revised forecast number of customers connected to the system at the end of year t-1. This forecast is made at the end of year t-1 when amending the revenues that ought to have been allowed for year t-1. P CDLt-1 is the amount of revenue per customer days lost that the Commission will allow BGD to retain (forego) for reducing (increasing) the number of days lost per customer. The value is as shown in Table A (in year 2003 prices) converted into nominal values in year t-1. RFCDL t-1 is the revised forecast average number of days lost per connected customer in year t-1. This forecast is made before the end of year t-2. ACDL t-1 is the actual average number of customer days lost in year t- P t-1 It I t-1 1. Any changes in actual pass-through costs from those included in the revenues that ought to have been allowed in year t-1 as assessed in the year t-1. This includes, inter alia, changes in onshore and UK rates, insurance etc which the CER has indicated will be allowed on a pass-through basis. is the average Euribor rate in year t. The Commission will apply a factor of 2% plus Euribor to the under and overrecovery of revenues between 97% and 103% of revenues. Any over-recovery beyond this tolerance band will attract a charge of the Euribor rate +4%. Over and under-recovery within the tolerance limit will attract a financing rate of Euribor plus or minus 2%. Under-recovery below 97% will attract a financing rate of Euribor + 2%. is the average Euribor rate in year t-1. AR t-1 This is the actual revenue recovered in year t-1. 21

22 The Commission has yet to determine the parameter values to be used in the above equation. This will be done prior to publication of the Commission s final decision. Table 8: Parameter Values for Revenue Control Formula Year Bt (Euro m Year 2003) PCt ( Year 2003) Ct (in thousands ) CDLt (in days) PCDL (in EuroYear 2003)

23 5. Structure of Distribution Tariffs The March consultation paper on principles discussed different methods including statistical and connection based methods for determining distribution tariffs. The 15 th May workshop also discussed issues relating to tariff structure and implications of changing the structure. The responses to the consultation were divided in the tariff method they preferred but almost all were of the view that tariffs should reflect the costs that users impose on the system. Some respondents also expressed the concern that some anomalies concerning the definition of transmission and distribution assets should be corrected to prevent some customers from paying more than the costs they impose on the system and other customers paying less. In general, the respondents to the consultation paper and those who attended the workshop endorsed the principles that: Customers should pay for the costs they impose on the system; cross-subsidy between customer categories should be prevented; tariff rebalancing should ensure that adverse impacts are ameliorated through a gradual transition to rebalanced tariffs, if that is required. The Commission will review the customer impact of tariff changes. The Commission is currently considering grandfathering certain customers who may be affected when the charging methodology is revised, particularly if there is a change in the definition of the point at which the customer is connected. On the basis that a revised tariff methodology may result in significant changes to tariffs faced by some customers, we have asked BGD to review customer impacts and recommend a transition path to re-balanced tariffs. We have asked BGD to submit their tariff proposals by the end of June. 23