deloitte draft tpcr report v2 - ofgem · questionnaire under 3 headings - data clarification, cash...

This Draft Report has been prepared in line with our agreed scope of work. This Report is still draft and subject to our internal

review procedures and accordingly, we reserve the right to add, delete and/or amend the Report as appropriate. No party may place any reliance whatsoever upon this draft of the Report.

Strictly Private and Confidential

Results of work carried out by Deloitte in support of Ofgem’s Transmission Price Control Review 2007-2012 Draft report April 2006

Deloitte Athene Place 66 Shoe Lane London EC4A 3BQ

Deloitte Report on TPCR support to Ofgem April 2006

Draft Report Strictly Private and Confidential 2

Contents Glossary Disclaimer

1 Executive Summary..................................................................................................6 1.1 Introduction..................................................................................................................6

1.2 Workstream A: Accounting issues ................................................................................7

1.3 Workstream B: Business support services...................................................................14

1.4 Effect of NGC/Transco merger ...................................................................................16

1.5 Workstream C: Top-down analysis .............................................................................18

2 Workstream A: Accounting Issues..........................................................................22 2.1 Introduction................................................................................................................22

2.2 Scope..........................................................................................................................22

2.3 Approach....................................................................................................................23

2.4 Definitions..................................................................................................................24

2.5 Structure of this section ..............................................................................................24

2.6 Categorisation of Base Year Operating Costs..............................................................25

2.7 Year on Year Analytical Review of Total UK Transmission Operating Unit Costs .....29

2.8 Reconciliation of HBPQ to Statutory and Regulatory Accounts ..................................32

2.9 NG’s Adjustment to Accounting Operating Costs to Obtain ECOC ............................33

2.10 Rationale for Adjustments ..........................................................................................38

2.11 Analysis of NG’s non-operational capex.....................................................................40

2.12 Issues Arising from the Review of the HBPQ and the Reconciliation of HBPQ to

ECOC.........................................................................................................................43

2.13 Cash versus non-cash items ........................................................................................45

2.14 Atypical and non-recurring items................................................................................48

2.15 Capitalisation Policy...................................................................................................50

2.16 General Accounting Principles....................................................................................55

2.17 Related party transactions ...........................................................................................58

2.18 Historic ECOC Analysis .............................................................................................61

2.19 Conclusion .................................................................................................................64

3 Workstream B: Business Support Services ............................................................65 3.1 Introduction................................................................................................................65

3.2 Approach....................................................................................................................65

3.3 Scope..........................................................................................................................67

3.4 Breakdown of Controllable Costs ...............................................................................68

3.5 Benchmarks Identified................................................................................................71

3.6 Benchmarking Analysis ..............................................................................................74

3.7 Operational Telecoms.................................................................................................75

3.8 Corporate Centre ........................................................................................................78

3.9 HR & Scheme Trainees ..............................................................................................84

3.10 Finance (Business Services Finance and Transmission Finance) .................................89

3.11 Procurement and Logistics..........................................................................................94



3.12 Communications.........................................................................................................98

3.13 Legal ........................................................................................................................101

3.14 Safety, Health, Environment and Security.................................................................103

3.15 Regulation ................................................................................................................105

3.16 Internal Audit ...........................................................................................................108

3.17 Conclusions ..............................................................................................................110

4 Effect of the NGC/Transco merger .......................................................................111 4.1 Introduction..............................................................................................................111

4.2 Original target for merger savings.............................................................................111

4.3 External view of possible merger savings .................................................................111

4.4 Revision by National Grid of merger savings in 2003 ...............................................112

4.5 Evidence of Merger Savings in Each Category .........................................................113

4.6 Implications for Savings Achieved ...........................................................................115

4.7 Implications for any Savings Still to be Achieved .....................................................117

4.8 Overall view.............................................................................................................118

5 Workstream C: Top-Down Efficiency Assessment................................................119 5.1 Introduction and scope of work.................................................................................119

5.2 Time trends for NG’s businesses...............................................................................119

5.3 Comparisons with other privatised infrastructure companies.....................................127

5.4 Comparisons with International Transmission Companies ........................................147

5.5 Conclusions ..............................................................................................................162 Appendices Appendix 1: Summary of the provisions analysis provided by National Grid Appendix 2: Summary of cash costs analysis



Glossary The following abbreviations are used in this report: BPQ Business Plan Questionnaire

Capex Capital expenditure

DNO Electricity Distribution Network Operators

ECOC Efficient Cash Operating Costs

ESO Electricity System Operator

ETO Electricity Transmission Owner

EU European Union

FBPQ Forecast Business Plan Questionnaire

GSO Gas System Operator

GTO Gas Transmission Owner

HBPQ Historic Business Plan Questionnaire

IFRS International Financial Reporting Standards

NG National Grid Plc (formerly National Grid Transco Plc)

NGET National Grid Electricity Transmission Plc (formerly National Grid Company Plc)

NGG National Grid Gas Plc (formerly Transco Plc)

Opex Operational expenditure

RAV Regulatory Asset Value

Repex Replacement expenditure

RUOE Real Unit Operating Expenditure

SEC Securities and Exchange Commission

SPT Scottish Power Transmission Ltd

SHETL Scottish Hydro-Electric Transmission Limited

T&S Travel and Subsistence

TPCR Transmission Price Control Review

UK GAAP United Kingdom Generally Accepted Accounting Principles



Disclaimer

This draft report (the “Report”) has been prepared by Deloitte & Touche (“Deloitte”) for The Office of Gas and Electricity Markets (“Ofgem”) alone as part of Deloitte’s support to the Transmission Price Control Review being undertaken by Ofgem. This Report is still draft and subject to our internal review procedures and accordingly, we reserve the right to add, delete and/or amend the Report as appropriate. No party may place any reliance whatsoever upon this draft of the Report. The information contained in the Report has been obtained from a number of sources which are believed to be reliable but no independent verification of any statements has been made nor has any comment or verification been made in relation to statements or expressions of opinions made in the Report. Neither Ofgem nor Deloitte accept any liability in relation to any information from third party sources or any statement of opinion set out in the Report. Readers of the Report must form their own opinion as to the nature of the information contained in the Report. Any decision to invest, conduct business, enter or exit the markets considered in the Report should be made solely on independent advice and no information in the Report should be relied upon in any way by any third party. The Report does not constitute a recommendation to use or any endorsement of any of the markets or companies referred to in the Report. Ofgem is not constrained to act in accordance with the contents of the Report or the conclusions made in it. Deloitte has endeavoured to ensure that data and material in the Report is accurate but does not accept liability for any omission or error contained in the Report. The information and opinions in this Report are subject to change without notice. No representation or warranty (express or implied) is made in relation to the accuracy or completeness of any information or opinions contained in the Report. The materials in the Report do not constitute financial or other professional advice. Neither Deloitte nor Ofgem is liable for any direct, indirect, special, incidental or consequential damages arising out of the use (or the inability to use) the material in the Report, including any action or decision taken as a result of using such material. This includes but is not limited to the loss of data or loss of profit. Deloitte is regulated by the Financial Services Authority.



1 Executive Summary

1.1 Introduction

1.1.1 Ofgem is reviewing the transmission price controls to take effect in April 2007. The review applies to the three electricity transmission licensees National Grid Electricity Transmission (NGET), Scottish Power Transmission (SPT) and Scottish Hydro-Electric Transmission Limited (SHETL) and to the licensed gas transporter for the gas transmission system, National Grid Gas (NGG). This is the first time the four price controls have been reviewed together.

1.1.2 Wherever possible, Ofgem is seeking to use this opportunity to provide a consistent approach between gas and electricity price reviews (which currently differ in some respects) as well as retaining consistency between the treatment of the three electricity transmission networks.

1.1.3 We have been appointed to support Ofgem in its review of operating costs for National Grid (NGET and NGG) for the current Transmission Price Control Review. Deloitte has not been asked to carry out analysis of the material provided by the Scottish electricity transmission businesses or to assist in determining their efficient operating costs.

1.1.4 Our work has been divided into the following four workstreams:

• Workstream A: Accounting issues. The main objective of this Workstream is to assist Ofgem in forming judgements about the extent to which the costs reported by NG correspond to a cash-based reflection of efficiently incurred controllable operating costs (ECOC), although the Workstream does not focus on the extent to which such costs have been efficiently incurred. This involves, for example, the removal of extraneous non-cash items, including those related to provisions and atypical items.

• Workstream B: Business support services. The main objective of this Workstream is to assist Ofgem in forming judgements about whether the level of costs in some business support services corresponds to efficiently incurred cost levels. We have also analysed merger savings in these areas, which are presented under a separate section in this report.

• Workstream C: Top-down benchmarking. The main objective of this Workstream is to assist Ofgem in forming judgements about the overall level and comparable efficiency of operating costs.

• Workstream D: Cost allocation. This Workstream is intended to provide Ofgem with both technical and practical advice on cost allocation issues. The results of our work have been included in a separate report “Comments on Ofgem's review of NGT's cost allocation methodology” submitted in February 2006.

1.1.5 The results of our work on workstreams A, B and C are set out in this report. All costs and revenues in this report are in real terms in 2004/05 prices, unless otherwise stated.



1.2 Workstream A: Accounting issues

Objective

1.2.1 The objective of Workstream A is to determine whether the costs in the HBPQ are correctly classified to represent continuing cash operating costs. Given the approach to defining ECOC agreed with Ofgem this requires consideration in particular of the following issues:

• the exclusion of non-controllable costs;

• non-cash items;

• exceptional and non-recurring items;

• capitalisation policy, including the treatment of overheads, direct costs and non-operational capex;

• accounting standards, in particular adoption of IFRS; and

• transfer pricing and related party transactions.

Approach

1.2.2 In order to perform the work described above the following approach was adopted:

• We reviewed NG’s HBPQ responses: the HBPQ was assessed in the context of reviewing overall report and accounts data as well as the regulatory and statutory accounts for the years 01/02-04/05.

• We prepared an accounting questionnaire: the questions were set out in the questionnaire under 3 headings - data clarification, cash versus non-cash, and normalisation. This questionnaire also included questions relating to capitalisation policies, related party charges and the distinction between operational and non-operational capex.

• We co-ordinated with the capex consultants: we liaised with the capital expenditure consultants for gas and electricity in order to ensure NG’s responses were consistent for both the capital expenditure and operating expenditure workstreams.

• We met with the business: we met with NG in order to cross-check responses in the HBPQ and to our questionnaire.

• We proposed adjustments: using the data provided to us, we proposed adjustments, in accordance with the agreed definition of ECOC.

Structure of Workstream A section

1.2.3 The Workstream A: Accounting Issues section starts by focusing on NG’s response to the HBPQ and the adjustments NG has made to get from accounting costs to NG’s view of ECOC.

1.2.4 This is followed by sub-sections covering issues Deloitte has identified with respect to NG’s data and the adjustments that may be required for the following types of issues:


• the exclusion of non-cash items;

• the exclusion of exceptional and non-recurring items;

• capitalisation policy;



• the adoption of new accounting standards; and

• transfer pricing and related third party transactions.

1.2.5 The final sub-section summarises our conclusions on the adjustments that could be made to the base year costs.

NG’s response to the HBPQ

1.2.6 As part of the Price Control Review process NG were asked by Ofgem to complete a Historic Business Plan Questionnaire (HBPQ). The HBPQ includes tables which NG populated with financial information for the historic years 2001/02 to 2003/04 and for the base year 2004/05.

1.2.7 Table 1-1 summarises the costs reported in the HBPQ split by forms of control for the base year 2004/05.

Table 1-1: Controllable and non-controllable operating costs by forms of control in the base year

Electricity

TO Electricity

SO Gas TO

Gas TO

Non-transmission

Total

Controllable costs 162.7 43.6 63.9 30.2 12.7 313.1

Non-controllable costs

281.6 323.9 104.8 90.8 0.9 802.0

Total 444.3 367.5 168.7 120.9 13.6 1,115.1

Source: HBPQ data

1.2.8 These costs were reconciled to the audited statutory or regulatory accounts for 2004/05 so as to assess the consistency of the data provided in the HBPQ.

1.2.9 NG has adjusted these costs to determine their view of ECOC. Our report shows this information in both graphical and tabular formats. See Figures 4-4 to 4-7 and Tables 4-10 to 4-13. All of the numbers included in these Figures and Tables were provided by NG.

Exclusion of non-controllable costs

Excluded services costs

1.2.10 Excluded services are defined in the Transmission Operators Special Licence Condition. The treatment of excluded service costs are outside of the scope of this report. For the purposes of this report they have been removed from ECOC.

Employee share option scheme costs

1.2.11 These costs arise for the first time in the base year because during 2004/05 NG adopted FRS20 ‘Share Based Payments’. The standard requires that where shares or rights to shares are granted to employees, a charge should be recognised in the profit and loss account based on the fair value of the shares or options at the date the grant. These costs result from the application of an accounting standard and do not represent a cash cost to NG and as such have been removed from ECOC.

Balancing services, storage and shrinkage costs

1.2.12 Balancing service costs relate to the electricity transmission business only. These costs are paid to power stations to increase their energy supply and to large energy users to reduce their energy demand in order to balance the network. This cost is remunerated through external ESO schemes and so should be excluded from ECOC for the purposes of the price control review.



1.2.13 Shrinkage and storage costs are costs incurred in operating the gas network. At present these costs are remunerated through the GSO incentive scheme so have been excluded from ECOC for the purposes of this report.

1.2.14 Table 1-2 shows the proposed ECOC adjustments with respect to the exclusion of non-controllable costs.

Table 1-2: Proposed ECOC adjustments

ETO £m

ESO £m

GTO £m

GSO £m

Costs to be removed from ECOC: Excluded services costs 1.1 - - - Employee share option scheme costs 3.3 0.7 0.6 0.5 Total 4.4 0.7 0.6 0.5 Costs remunerated elsewhere and thus should be removed from ECOC:

Balancing services incentive scheme direct costs

- 303.1 - -

Shrinkage - - - 58.4 Storage costs - - - 17.5 Total - 303.1 - 75.9 Source: Deloitte analysis

Exclusion of non-cash costs

1.2.15 Cash costs added into ECOC in respect of the merger and restructuring provision are exceptional expenses. They do not represent the ongoing cash costs of the business and so should be removed from ECOC. See Table 1-3 for details of these costs.

1.2.16 The £0.5m of environmental provision utilisation in 2004/05 relates to cleaning up past contamination. The level of expenditure for this type of work is driven by legal obligations and the condition of NG’s sites. This cash cost has been removed from ECOC in order to highlight the item. Ofgem will need to take a view on whether to remunerate NG for environmental remediation.

1.2.17 Onerous lease costs in respect of the Brookmead property in Guildford have been added back to ECOC by NG. The £1.4m represents ongoing annual cash costs until 2015 in respect of a 25 year lease signed in 1990, with no break clauses. The cash costs of the onerous lease could be covered by income from the subletting the property and as such the cash costs have been removed from ECOC.

1.2.18 The accounting cost of £4.3m in respect of GSO other provisions relates to NGG’s obligation to deliver EU Emissions Trading Scheme Emissions Allowances. This cost is one which will be settled in cash and is recurring, accordingly the cost has been added back into ECOC.

1.2.19 Table 1-3 summarises the proposed ECOC adjustments arising from the above analysis of cash versus non-cash items.

Table 1-3: Proposed ECOC adjustments resulting from the review of cash versus non-cash items ETO

£m ESO £m

GTO £m

GSO £m

Remove restructuring exceptional costs (1.6) - (2.2) (3.1) Remove environmental clean up costs (0.5) - - - Remove onerous lease costs (1.4) - - - Add back carbon emission costs - - - 4.3 Total (3.5) - (2.2) 1.2 Source: Deloitte analysis



Exclusion of exceptional and non-recurring items

Exceptional restructuring and reorganisation costs

1.2.20 NG have added to ECOC £0.8m of exceptional costs relating to the sale of the distribution network businesses. This is a non-recurring atypical item and it is proposed that it should be removed from ECOC for the purposes of the price control review.

1.2.21 Included within the ETO operating costs in the HBPQ for 2004/05 are £0.1m of severance costs relating to the restructuring of the business. This is not an ongoing cash cost to the business and similarly should be removed from ECOC.

Efficiency costs

1.2.22 In the HBPQ 2004/05 other controllable costs include £3.5m of ‘investment for efficiency’ costs. These costs relates to consultancy support associated with the “Ways of Working” Review. These costs are not an ongoing cost to the business and as such they should not be included in ECOC.

PLUGS

1.2.23 In respect of PLUGS, NG have made an adjustment to increase the ETO ECOC by £11.9m. The PLUGS costs are not an ongoing cost to the business and as such they should not be included in ECOC but should be taken account of in projections. In addition, included in ECOC is an accounting cost of £0.2m which should also be removed bringing the total ECOC adjustment to £12.1m.

Subsidence repair costs

1.2.24 The network strategy costs for ETO include £0.6m for emergency subsidence repairs at the Littlebrook substation. This does not appear to be a continuing cost and so an adjustment should be made for this in order to normalise costs in the base year.

Material costs

1.2.25 Material costs for engineering services increase by £11.1m from £14.4m in 2003/04 to £25.5m in 2004/05 for Electricity TO. This increase included:

• £1.9m: Additional focus on site care activities including the roll out of national outsourced contracts for statutory testing such as mechanical, electrical and legionella tests.

• £1.9m: Additional costs of cable faults.

• £1.2m: Higher levels of planned and unplanned expenditure on maintenance and repairs to high voltage primary plant, in particular, higher costs incurred on supergrid transformers.

1.2.26 These items appear to relate to atypically high levels of costs when compared to the prior year. An adjustment to ECOC in respect of these costs may be required in order to achieve a normalised cost base in the base year.

Control centre rationalisation costs

1.2.27 During 2004/05 the gas Area Control Centres were rationalised to a single site at Hinckley in order to deliver cost savings going forward. Non-recurring operating costs of £2.4m were incurred as double manning was provided during the period of transition between live control rooms and as staff were relocated. This is not an ongoing cash cost to the business and should be removed from ECOC.



1.2.28 Table 1-4 summarises the proposed adjustments arising from our analysis in respect of exceptional and non-recurring items.

Table 1-4: Proposed ECOC adjustments in respect of exceptional and non-recurring items

ETO £m

ESO £m

GTO £m

GSO £m

Network sales costs - - (0.7) (0.1) Severance costs (0.1) - - - Investment for efficiency costs (3.0) - - (0.5) PLUGS (12.1) - - - Littlebrook subsidence repairs (0.6) - - - Atypical materials costs (5.0) - - - Control centre rationalisation costs - - - (2.4) Total (20.8) - (0.7) (3.0)

Source: Deloitte analysis

Capitalisation Policy

1.2.29 Within the boundaries of accounting standards there are areas of judgement involved with capitalisation of costs. In order to determine whether NG was generally capitalising a large proportion of costs a comparison to the Scottish transmission companies and the DNOs was undertaken.

1.2.30 It is noted that both NGET and NGG capitalise a lower proportion of expenditure than all of the DNOs and Scottish Power Transmission. This provides some evidence that NG as a company does not adopt aggressive accounting policies regarding capitalisation.

1.2.31 Some companies use cost allocation models to allocate indirectly attributable costs relating to overheads and salaries of support functions to capital projects. These models are not used within NG and there is no evidence of capitalisation of these types of costs.

Non-operational capex

1.2.32 Non-operational capital expenditure is not an accounting concept but one defined by Ofgem in the context of Price Controls. This type of expenditure is capitalised and included on the entity’s balance sheet from an accounting standpoint. In the context of the Price Control this type of capital expenditure is treated as operating expenditure i.e. the expenditure is not included in the RAV but included in the Price Control calculation.

1.2.33 Following clarification on the definition of non-operational capex, NG have resubmitted data on the levels of costs incurred during the previous price control period. This data is shown in Table 1-5 below. Note NG have currently not provided sufficient detail to assign specific non-operational capital expenditure to forms of control. Therefore assumptions have been made to allocate this expenditure to specific forms of control.

Table 1-5: Resubmitted non-operational capex figure by form of control ETO

£m ESO £m

GTO £m

GSO £m

Commercial vehicles 2.5 - - - Plant and machinery - - - - Small tools & equipment - - - - Office equipment - - - - Land and building used for administrative purposes

0.8 0.8 0.8 0.8

IT (including telecoms) 1.2 1.2 - - Total 4.5 2.0 0.8 0.8

Source: National Grid analysis



1.2.34 NG appears to have appropriately added back non-operational capex to ECOC and no adjustments are proposed. Discussions are continuing between NG and Ofgem regarding which types of expenditure are considered non-operational capex. If the classification of costs is changed, an adjustment to the amounts reported above may be required. The responsibility for the finalisation of these figures lies with Ofgem.

The adoption of new accounting standards

1.2.35 This section deals with the impact of changes to general accounting principle on ECOC, principally the adoption of IFRS. With effect from 1 April 2005, NG is required to report its consolidated financial results in accordance with International Financial Reporting Standards (IFRS) having previously reported under UK GAAP.

1.2.36 In NG’s IFRS conversion statement adjustments were made to operating costs under the following headings:

• depreciation;

• amortisation;

• payroll costs;

• electricity purchases;

• replacement expenditure; and

• other operating charges.

1.2.37 None of these adjustments impact the UK transmission business ECOC as the adjustments either relate to non-cash items such as depreciation and amortisation or relate to the NG’s US business or UK distribution business.

1.2.38 It is concluded that the conversion to IFRS will not have a material effect on ECOC.

Transfer pricing and related party transactions

1.2.39 Within the total operating costs included in the HBPQ are costs which have been charged by other NG Group companies or other NG business units for services rendered. The risk in relation to these costs is that they may not represent the cost that would be achieved using an independent third party to provide the same services. If it were the case that the prices charged by another NG Group company or business unit to the transmission businesses was higher than an arms length price then the costs in the HBPQ would be artificially inflated.

1.2.40 Network Mapping provides a range of specialist products to worldwide power utilities. It is noted that only 30% of the turnover of Network Mapping is external to NG and therefore the margin of £0.5m should be removed from ECOC. The entire internal margin arises in the electricity transmission business and it is assumed 100% of this arises within ETO.

1.2.41 Advantica provides technical support for gas specific activities such as forensic investigations and technical standard setting and review. It also provides technical training services. The margin of £0.1m has been assumed to wholly relate to GTO and has been removed from ECOC as only 53% of Advantica’s business is external to NG.

1.2.42 NGC Leasing provide company cars for NGET staff. A margin of 9% is earned by NGC Leasing on its charges to NGET. Since the total charges from NGC Leasing to NGET are only £2.3m this equates to a mark-up of £0.2m. This margin has been assumed to wholly relate to ETO and has been removed from ECOC as none of NGC Leasing’s business is external to NG.

1.2.43 Insurance costs are being reviewed in detail by Marsh and therefore fall outside of the scope of this report. However, it is noted that £5.5m and £2.9m margins are earned



from the electricity and gas transmission business respectively. As none of the insurance companies’ business is external to NG, these margins have been removed from ECOC.

1.2.44 Table 1-6 summarises the proposed adjustments arising from our analysis in respect of related parties.

Table 1-6: Proposed ECOC adjustments in respect of related parties

ETO £m

ESO £m

GTO £m

GSO £m

Costs to be removed from ECOC Network Mapping 0.5 - - - Advantica - - 0.1 - NGC Leasing 0.2 - - - Insurance costs 4.6 0.9 2.8 0.1 Total 5.3 0.9 2.9 0.1


1.2.45 Table 1-7 sets out a summary of the proposed adjustments arising from the analysis above.

Table 1-7: Summary of proposed adjustments to base year ECOC

Ref ETO ESO GTO GSO Total

£m £m £m £m £m

ECOC (per NG) 190.5 349.4 67.3 105.8 713.0

Adjustments proposed by Deloitte to amend ECOC

Exclusion of non-controllable costs Table 2-20 (4.4) (0.7) (0.6) (0.5) (6.2)

Cash versus non-cash items Table 2-25 (3.5) - (2.2) 1.2 (4.5)

Atypical and non-recurring items Table 2-26 (20.8) - (0.7) (3.0) (24.5)

Capitalisation policy - - - - -

Adoption of IFRS - - - - -

Related party transactions Table 2-33 (5.3) (0.9) (2.9) (0.1) (9.0)

Total adjustments (34.0) (1.6) (6.4) (2.4) (44.4)

ECOC including possible adjustments 156.5 347.8 60.9 103.4 668.6

Items included in ECOC that should be considered separately to operating costs for the purposes of the price control review

Balancing services charge Table 2-20

- (303.1) - - (303.1)

Shrinkage Table 2-20

- - - (58.4) (58.4)

Storage costs Table 2-20

- - - (17.5) (17.5)

Non-operational capex Table 2-28 (4.5) (2.0) (0.8) (0.8) (8.1)

Total (4.5) (305.1) (0.8) (76.7) (387.1)




1.3 Workstream B: Business support services

Scope and approach

1.3.1 The objective of this Workstream was to provide benchmarking information to enable Ofgem to make an assessment of whether certain business support service costs are at the appropriate level by comparing them with external benchmarks. For some services, this includes a qualitative assessment of the function based on our experience (e.g. Procurement and Finance). We have also considered a range of possible levels of benchmark costs.

1.3.2 Our approach included the steps set out below.

• Review of HBPQ responses: we reviewed the HBPQ data submitted by National Grid, focusing mainly on changes in operating costs related to business services.

• Preparing questions on business services: the review of the HBPQ gave rise to around 90 questions which were submitted to National Grid in order to complete our understanding of the data and narrative submitted.

• Meeting with the company: we followed up our questions on business services with meetings with National Grid to discuss issues and seek further clarifications on the data provided to us in the HBPQ.

• Identification, collection and normalisation of benchmarking data: we identified potential sources of benchmarking data for our analysis. This was collected and normalised for comparison with the HBPQ data for National Grid.

• Analysis of National Grid business services costs: the costs of business services were compared with the benchmarking data collected to assess the efficiency of National Grid.

• Drawing conclusions and reporting: drawing together all the evidence collected from benchmarks, discussions with the company and responses to questions, we have formed and presented our view on business services costs for 2004/05.

1.3.3 The scope of our work, as defined by Ofgem, did not include all of National Grid’s business services. The following table sets out which business services, as set out in the HBPQ, are within the scope of the benchmarking analysis and those that are outside the scope. The business services included within scope account for 38% (£120m) of the £313m total business services controllable costs in 2004/05.

Table 1-8: Business services within and outside of scope

Business Services 2004/05

Controllable costs

Within Scope

Corporate Centre, Operational Telecoms, HR & Scheme Trainees, Business Services Finance, Procurement and Logistics, Legal, Safety Heath Environment and Security (SHES), Communications, Regulation and Internal Audit

£120m

Outside of Scope

IS, Insurance and Property £193m

Total All business services £313m



Summary results from our analysis

1.3.4 The overall view from our analysis of the business support services is that the costs for 2004/05 compare favourably to our chosen high level benchmarks. These functions were key in delivering merger savings.

1.3.5 The sum of potential cost adjustments for 2004/05 ranges from £2.8m to £9.9m (2.3% to 8.2%) in the business services areas covered by this section of the report (Table 1-9).

1.3.6 Potential adjustments at the lower end of the scale include efficiencies under “corporate affairs” (includes part of Corporate Centre costs and Communication costs), Procurement and Logistics and Business Services Finance. Other functions did not exhibit significant variations relative to average or median benchmarks.

1.3.7 We have also suggested a higher range of potential efficiency adjustments. This has taken a more optimistic position by comparing National Grid with top quartile performance. Adjustments in this area covered higher savings for “corporate affairs”, Procurement and Logistics and Business Services Finance. It also includes adjustments for the core HR function, Internal Audit and Operational Telecoms.

1.3.8 We have not proposed any adjustments to Legal, SHES and Regulation, given the results of the benchmarking analysis conducted in these areas.

Table 1-9: Summary of potential savings in business services (2004/05) (£ million)

Business Area

Total

Controllable

Operating

Costs

Potential

Adjustment

(%)

low high

Operational Telecoms 17.2 0.0 -0.1 17.2 17.1 0%-0.6%

Corporate Centre 34.3 -0.9 -3.3 33.4 31.0 3%-10%

HR & Scheme Trainees 21.0 0.0 -0.8 21.0 20.2 0%-4%

Procurement & Logistics 11.5 -0.6 -1.2 10.8 10.3 5%-10%

Business Services Finance 10.2 -0.9 -1.7 9.3 8.6 9%-17%

Communications 5.3 -0.4 -2.7 5.0 2.7 7%-50%

Legal 5.8 0.0 0.0 5.8 5.8 0%

SHES 11.4 0.0 0.0 11.4 11.4 0%

Regulation 2.0 0.0 0.0 2.0 2.0 0%

Audit 1.6 0.0 -0.1 1.6 1.5 0%-9%

Total 120.2 -2.8 -9.9 117.4 110.4 2.3%-8.2%

Transmission Finance 4.1 -0.42 -0.76 3.6 3.3 9%-17%

Total (incl Trans. Finance) 124.3 -3.2 -10.6 121.1 113.7 2.6%-8.6%

Deloitte

Estimates

2004/05

Potential

Savings

Source: Deloitte benchmarking analysis



1.4 Effect of NGC/Transco merger

Introduction

1.4.1 We have analysed the impact on costs of the merger between NGC and Transco in 2002. We have referenced external reports from third parties, National Grid presentations and documents produced for NGC and Transco by their consultants. We also refer to presentations made by National Grid to Ofgem which focused on analysing merger savings using data from its HBPQ submission.

Target for merger

1.4.2 At the time of the merger announcement in mid-2002, the initial expectations for savings were of at least £100m per annum by the end of the first full financial year of the merged company (i.e. 2003/04). This was later revised in 2003 to £135m. Brokers reports issued in 2002 and 2003 shared the view that merger savings of at least £100m were possible, with some suggesting up to £225m in savings could be made.

1.4.3 The main areas targeted for savings are shown in Table 1-10. These include significant savings in Corporate Centre, through the combination of NGC and Transco’s head office costs in a single site and by eliminating duplicate roles. Savings were also expected in support services, IS and procurement. Fewer savings were expected from combining the engineering services, given the very different skill sets of the field forces.

Table 1-10: Breakdown of merger savings by business area Area Impacted £m

Corporate Centre 30

Information Systems 23

Business Services 17

Electricity Transmission 14

Procurement 24

Non-Regulated 18

Tax 4

Treasury 6

Total 135 Source: National Grid FBPQ submission

Analysis of merger savings

1.4.4 The absence of data for 2001/02 for Transco in NG’s response to the HBPQ was the main factor limiting our ability to assess the savings arising from the merger. NG had notified Ofgem of the difficulty in obtaining data for Transco for 2001/02 in a way which is comparable to the remaining HBPQ responses. Ofgem agreed that NG did not have to submit 2001/02 data for Transco as part of its HBPQ submission.

1.4.5 National Grid presented a summary of the savings achieved by business service function since 2001/02 using the HBPQ submission as the basis for the analysis. NG also presented an allocation of the merger savings to the Transmission business. This analysis is shown in Table 1-11.



Table 1-11: Allocation of HBPQ merger savings analysis to Transmission

£m Forecast in 2003

NG PCR analysis

Savings allocated to Electricity

Savings allocated to Electricity Tx.

Savings allocated to Gas

Savings allocated to Gas Tx.

Total Tx. savings (gas and electricity)

Corporate Centre 30 39 4 4 18 4 8

IS 23 33 5 28

Business Services 17 31 13 17

18 7 24

Sub-total 70 103 22 21 64 11 32

Electricity Transmission

14 5

5 5 - - 5

Procurement 24 24

Non-Regulated 18 18

Tax 4 4

Treasury 6 6

Could not be quantified using HBPQ data

Total 135 160 27 26 64 11 37

Source: National Grid, presentation to Ofgem 21 February 2006; Tx. = Transmission; PCR = Price Control Review

Overall view

1.4.6 The absence of a complete dataset in the HBPQ for Transco covering 2001/02 has not allowed us to conduct our own analysis of merger savings. This section has mainly referred to analysis carried out by NG, using the HBPQ as a reference, and has gone some way to address the data issue.

1.4.7 It is clear from the HBPQ that merger savings have occurred, in particular for business support services over the 2002/03 to 2004/05 period. Savings in Corporate Centre, IS and Business Services appear to have exceeded NG’s initial merger savings expectations. Therefore, it would appear that NG has managed to extract the bulk of merger savings from these areas.

1.4.8 The analysis and data presented by NG does not allow for a “no-merger” scenario to be constructed. Therefore, we are not able to identify how far costs would have changed if the merger had not taken place. Certain savings would probably have been achieved if the merger between NGC and Transco had not taken place. However, it is clear that there are other areas (e.g. Corporate Centre) where the majority of the savings since 2001/02 can be directly attributed to the merger.



1.5 Workstream C: Top-down analysis

Introduction

1.5.1 The focus of Workstream C is to provide analysis to inform Ofgem’s judgements on the overall efficiency of operating costs incurred by the transmission businesses. This top-down analysis examines benchmarks and trends in the following three areas:

• long term trends in controllable operating costs for gas and electricity transmission;

• productivity gains in UK privatised infrastructure companies since their privatisation; and

• international comparisons with other electricity transmission companies in Europe and the USA, and with Scottish transmission companies.

Long term trends

1.5.2 Using data from the HBPQ and NGET’s regulatory accounts, we examined controllable costs in electricity transmission since the introduction of incentive regulation at privatisation. NGET has experienced a marked decline in controllable transmission costs since privatisation in 1991 (Figure 1-1), with controllable costs more than halving between 1991 and 2005. From 1999/2000 onwards, controllable costs have decreased more slowly, at approximately 4% per annum in real terms, compared to the 6% reduction per annum experienced in the years before 1999/2000.

Figure 1-1: Historical analysis of electricity transmission (NGET) controllable costs (1990/01 – 2004/05)

0

100

200

300

400

500

600

90/91 91/92 92/93 93/94 94/95 95/96 96/97 97/98 98/99 99/00 00/01 01/02 02/03 03/04 04/05

Financial Year End

£'m

(2004/5 prices) *

HPBQ controllable costs (ETO and ESO)

HPBQ total operating costs less rates, depreciation and non-controllable system operatorcostsRegulatory accounts controllable costs for transmission (payroll and other costs)

Merger

Beginning of

previous price

control period

Source: NGET regulatory accounts; HBPQ data; Deloitte analysis

1.5.3 Similarly, we looked at trends in controllable costs for gas transmission. This was hindered by the bundling of transmission together with gas distribution in the regulatory accounts, denoted as transportation. By additionally examining the statutory accounts and information in the HBPQ, we were able to assess trends in transmission alone for the past five years, as well as in transportation since privatisation. As with electricity transmission, most of the large cost reductions in transportation controllable costs



occurred in the early years after privatisation in 1991. However, there have also been gains in recent years, with transmission controllable operating costs falling by 3.4% annually in real terms since the merger with NGC in 2002/03.

1.5.4 Furthermore, we reviewed the actual performance of electricity and gas Transmission Operator (TO) controllable operating costs relative to the Ofgem allowance. During the last price control, NGET underperformed the price control allowances for controllable operating costs. The net present value of costs over the price control period were almost £40m greater than those allowed by Ofgem, with annual cost reductions 0.7% smaller than those required by Ofgem. This is despite the merger, which was not anticipated when the price control was set and is said by NG to have generated large savings.

1.5.5 NGG outperformed the price control, both in terms of annual cost reductions and overall costs. It is difficult to draw many conclusions from this, due to the alleged over-allocation of costs to the Transmission Owner (offset with the NGG price control by an under-allocation to the distribution business) at the last price control.

Productivity gains in other UK privatised industries

1.5.6 We have analysed operating cost trends in comparator industries to NG. This is to assist in identifying the scope for operating efficiency improvements over the control period for NG.

1.5.7 We examined historic real unit operating expenditure (RUOE) reductions that other network monopolies have been able to achieve since their respective privatisations. The industries selected are electricity distribution and transmission, water, sewerage, telecommunications and rail, on the grounds that these are all network industries which have been privatised since 1984, and have been subject to some form of RPI-X regulation since privatisation. There are physical difference between the type of activities undertaken by NG and those of its comparators. However, this analysis is to determine operating cost reduction trends rather than the level of operating costs.

1.5.8 RUOE for each company has been determined from the operating costs reported in its Annual Report and Accounts and from data provided by the companies. Calculation of RUOE involves dividing the real operating expenditure (operating costs less depreciation) in a year by an appropriate output measure. The resulting RUOE values have been adjusted for volume growth and the impact of economies of scale. We also report the compound annual growth rate (CAGR) in RUOE over the period since privatisation.

1.5.9 RUOE calculations for NGG were problematic. Since privatisation in 1986, when British Gas plc was formed, there has been intense restructuring activity and multiple changes to the function of NGG. For this reason, robust time series data for NGG is not available. In fact, most studies examining RUOE reductions in privatised network utilities in the UK have not included the gas industry, due to the unreliability of the data. Hence, our RUOE estimates for the gas industry must be treated with caution.

1.5.10 Due to the historic bundling of transmission with distribution, denoted as transportation, we have also only been able to examine RUOE reductions for gas transmission over the past five years.

1.5.11 Our results are summarised in Table 1-12. It shows, for each company or industry, the period examined (generally the period since privatisation, unless data was not available or comparable), the output driver used, and both unadjusted and scale-adjusted CAGR in RUOE over the relevant period.



Table 1-12: Summary of RUOE reductions Period Output

measure CAGR (%)

Scale Adjusted CAGR (%)

Railtrack 1994/95 – 2004/05 Track route 3.8 3.8 Railtrack 1994/95 – 2004/05 Passenger Km -0.4 -0.1 BT 1997/98 – 2003/04 Call volume -8.2 -7.5

BT 1997/98 – 2003/04 Composite

measure -5.8 -5.2 Water 1997/98 – 2004/05 Base service -2.2 Sewerage 1997/98 – 2004/05 Base service -0.7 SPT 1990/91 – 2004/05 GWh -0.7 -0.2 SHETL 1990/91 – 2004/05 GWh -1.3 -0.6 Electricity Distribution 1990/91 – 2004/05 GWh -6.6 -6.2 NIE 1992/93 – 2004/05 GWh -7.4 -6.9 Gas Transportation 1996 – 2004/05 Gas throughput -7.7 -6.7 NGG 2000 – 2004/05 Gas throughput 0.2 0.3 NGET 1990/91 – 2004/05 GWh -5.5 -5.3

Source: Company accounts and data provided by companies; Deloitte analysis

1.5.12 The analysis shows a reduction in RUOE for most comparators, although the annual reductions have varied quite substantially between comparators.

1.5.13 The annual reductions in operating costs for NGET have been larger than those achieved in most other privatised network industries in the UK. However, companies such as BT and Northern Ireland Electricity, as well as the electricity distribution industry, have achieved greater annual cost reductions.

1.5.14 For gas transmission, small annual increases in operating costs have been experienced in the few years since the unbundling of transportation into transmission and distribution.

1.5.15 The most direct comparison for NGET appears to be with electricity distribution companies. There are a range of possible adjustments to distribution operating costs arising from a revised allocation of costs between distribution and supply in 2000/01. RUOE reductions recorded in Table 1-12 are for the most conservative option, i.e. assuming a greater impact of business separation on reported costs. On this basis, distribution companies have achieved annual RUOE reductions of 6.2% since privatisation and 7.8% in the past ten years.

1.5.16 However, less conservative adjustments were used by CEPA (2003)1 in a report which examined productivity improvements in the DNO’s. On this basis, distribution companies have achieved annual RUOE reductions of 6.9% since privatisation and 7.8% in the past ten years.

1.5.17 This compares with NGET’s annual reduction of 5.3% since privatisation and 5.2% in the past ten years. Although there are some factors specific to electricity transmission, such as the introduction of BETTA, it is not clear that these account for the majority of the difference. Had NG reduced operating costs at the same rate as the distribution business in the last ten years, it would have had operating costs approximately £68 million lower in 2004/05 by the most conservative estimate.

Comparisons with international transmission companies

1.5.18 We compared the performance of NG with that of international transmission companies. International comparisons are limited by lack of data availability,

1 2003, Cambridge Economic Policy Associates, ‘Productivity Improvements in Distribution Network Operators’, a report to Ofgem, November.



inconsistent basis of data, and differences in operating environment and history. The latter is particularly significant, given that NG is an unusually large and dense transmission network. This analysis gives more general indications of how NG compares to other companies rather than firm conclusions.

1.5.19 In the case of electricity transmission, comparisons are made using European and US electricity transmission companies. Comparisons are made on the basis of unit cost benchmarks, which examine the proportion of operating costs to various cost drivers, such as kilometres of high voltage line, peak load on the system and turnover. Our analysis does not show any evidence from international comparators that NGET is exceptionally efficient.

1.5.20 We have also compared NGET with the Scottish transmission companies, SHETL and SPT. These are likely to be better comparators for NGET, due to the common regulatory and accounting environment shared by the three firms. However, it must be noted that NGET’s operating environment differs substantially from that of the Scottish companies, being a far denser grid and on a far larger scale.

1.5.21 Our benchmark ratios were the proportion of controllable operating costs to kilometres of high voltage line and peak load on the system. On the basis of these measures, NGET compares more favourably against the two Scottish transmission companies. As expected, when unit costs are examined in terms of kilometres of high voltage line, NGET’s unit costs are higher than those of SPT and SHETL due to the differing densities of the networks. However, on the basis of peak load on the system, NGET has lower controllable unit costs than both SPT and SHETL.

1.5.22 Overall, it is not possible to conclude on the basis of this analysis that NGET is materially inefficient. The issues described earlier in this section, especially on data comparability and operating environment, show that there are other factors that may account for NGET appearing less efficient than some of its comparators.

1.5.23 No comparison similar to that for NGET is currently possible for gas transmission within the timescale and scope of this exercise, due the difficulties of obtaining unbundled operating costs data for transmissions. We are aware that the Council of European Energy Regulators (CEER) has commissioned a benchmarking study of European gas transmission tariffs. The report will be available to Ofgem as a member of CEER once it is released in the later half of 2006.



2 Workstream A: Accounting Issues

2.1 Introduction

2.1.1 The objective of this Workstream is to determine whether the costs in the HBPQ are correctly classified to represent continuing cash operating costs. This is intended to support any re-categorisations and reallocations that Ofgem may wish to carry out and as such focuses on the base year for the price control review, 2003-2004. Any reallocations raised within this report are to be supported with a clearly documented trail of explanations. Given the approach to defining ECOC agreed with Ofgem, this requires consideration in particular of the following issues:


• non-cash items;

• exceptional and non-recurring items;

• capitalisation policy, including the treatment of overheads, direct costs and non-operational capex;

• accounting standards, in particular adoption of IFRS; and

• transfer pricing and related party transactions.

2.2 Scope

Within Scope

2.2.1 The following costs are within the scope of this report in the context of the issues listed in paragraph 2.1.1:

Controllable costs Non-controllable costs

Net staff costs (including agency costs) Depreciation Materials Formula rates Subcontractors Transmission Licence Professional and consultancy fees Excluded Services Non salary staff costs (including T&S) Other non-controllable costs Rents and buildings Profit / loss on sale of fixed assets

Internal sales / purchases

Other controllable costs

Outside of Scope

2.2.2 The following are outside of the scope of this report:

• determination of FRS17 charges and pension contributions. Ofgem are to perform a review of any pension costs.

• review of the tax position. This responsibility lies with Ofgem.

• the efficiency of operating costs incurred is outside of the scope of this section of the report. The Workstream A objectives are concerned only with identifying cash operating costs with respect to the definition of ECOC.

• the balancing service incentive scheme costs and directly related costs associated with it. The responsibility for the review of these costs lies with Ofgem.

• excluded services costs and their treatment for the purposes of the TPCR. The responsibility for the review of these costs lies with Ofgem.



• the method by which costs are allocated to the forms of control from shared services (i.e. Electricity Transmission Owner, Electricity System Operator, Gas Transmission Owner and Gas System Operator). Shared services costs are expenses incurred centrally which are not directly attributable to the transmission businesses e.g., communications, legal or regulation.

2.3 Approach

2.3.1 In order to perform the work described above the approach described below was adopted.

Review of NG’s HBPQ responses

2.3.2 The HBPQ responses include data on historic years, 01/02, 02/03 and 03/04, as well as the Base Year, 04/05. The HBPQ was assessed in the context of reviewing overall report and accounts data as well as the latest regulatory and statutory accounts.

Preparation of accounting questionnaire

2.3.3 The review of the HBPQ gave rise to questions for the four forms of control which were set out in a questionnaire. The questions were set out in the questionnaire under three headings:

• Data clarification questions. These questions were designed to seek explanations for inconsistencies within the data and to provide further details of any instances where the HBPQ and accompanying appendices did not provide sufficient information.

• Cash versus non-cash questions. Questions under this heading were designed to aid us in calculating the necessary adjustments for any non-cash items identified during the review of the HBPQ.

• Normalisation questions. These questions were concerned with any unusual or one-off items identified during the review of the HBPQ.

2.3.4 This questionnaire also sought confirmation from the businesses among other things of the application of policies on capitalisation, the basis of market testing of related party charges and the distinction between operational and non-operational capex.

Co-ordination with capex consultants

2.3.5 Following NG’s responses to capitalisation questions, we liaised with the capital expenditure consultants for gas and electricity in order to ensure NG’s responses were consistent for both the capital expenditure and operating expenditure workstreams. This involved discussion of:

• the application of the capitalisation accounting policy;

• the treatment of replacement asset expenditure; and

• the identification of non-operational capital expenditure.

Meetings with businesses

2.3.6 We met with the businesses in order to cross-check responses in the BPQ and to our questionnaire.

Proposed adjustments

2.3.7 Each adjustment to the data provided to us by the four businesses was separately identified and is explained in our report using a documented trail of support. They are intended to be consistent with the agreed definition of ECOC.



2.4 Definitions

2.4.1 The following definitions provide Deloitte’s understanding of some of the terms used in this report. Where the definitions have been provided by an external source this has been noted.

Cash Costs

2.4.2 Deloitte have assumed that cash costs means costs that are or will be settled in cash, rather than actual cash paid during the year. The significance of this is that no adjustments have been made in respect of working capital or accruals movements as these derive from short term timing differences rather than a cash/ non-cash distinction. See Appendix 2 for analysis done on a cash paid in the year basis.

Controllable costs

2.4.3 Controllable costs are those operating costs for which NG are able to exercise some degree of control. For example the costs of renting premises and paying staff. These costs are largely included within ECOC since the price review is set so that NG are challenged to find greater efficiencies within these costs.

Non-controllable costs

2.4.4 These are costs which NG has no control over, for example transmission licence fees. These costs are largely removed from ECOC.


2.4.5 The definition of non-operational capex supplied by Ofgem was designed to be consistent with the definition used for the regulatory reporting for the electricity distribution business. The definition can be split into two parts as follows:

• Non-operational IT: IT equipment that is either located away from the network assets or does not relate to the control of those assets. This includes infrastructure and IT applications and excludes operational IT.

• Non-operational new assets & replacement: Expenditure on new and replacement assets which are not system assets. This includes vehicles (including mobile plant and generators), plant & machinery, small tools & equipment, office equipment, land and buildings used for administrative purposes, IT (including telecoms). This excludes system assets and company cars.

Forms of control

2.4.6 This collectively describes the ETO, ESO, GTO and GSO.

2.5 Structure of this section

2.5.1 The remainder of the Workstream A: Accounting Issues section is structured as follows.

2.5.2 Section 2.6 describes how NG has categorised its operating costs in the HBPQ, how these reconcile to statutory and regulatory accounts, and the adjustments NG has made to get from accounting costs to NG’s view of ECOC.

2.5.3 The following sub-sections describe, in order, the issues Deloitte have identified with respect to NG’s data and the adjustments to this that may be necessary for the following types of issues:


• the exclusion of non-cash items;

• the exclusion of exceptional and non-recurring items;



• capitalisation policy;

• the adoption of new accounting standards; and

• transfer pricing and related third party transactions.

2.5.4 The final sub-section summarises our conclusions on the further adjustments that could be made to the base year costs.

2.6 Categorisation of Base Year Operating Costs

2.6.1 As part of the Price Control Review process NG were asked by Ofgem to complete a Historic Business Plan Questionnaire (HBPQ). The HBPQ includes tables which NG populated with financial information for the historic years 2001/02 to 2003/04 and for the base year 2004/05.

2.6.2 The HBPQ includes tables which show the total shared service costs (see paragraph 2.6.9 below) incurred by NG and the allocation of these costs firstly between the regulated and non-regulated businesses, then between the electricity and gas transmission business and finally between the forms of control.

2.6.3 The HBPQ also includes tables which show the total transmission business unit costs (see paragraph 2.6.12 below) and their allocation between the forms of control.

2.6.4 The method used by NG to allocate the costs is not shown in the HBPQ and is outside of the scope of this report. This applies for both shared service costs and transmission business unit costs.

2.6.5 Figure 2-1 shows how the UK transmission business of NG is organised.

Figure 2-1: NG Transmission Business Organisation Chart

Forms of Control

Legal Entities

Operational

NG

NGET NGG

ESOETO GTO GSO

UK TRANSMISSION OPERATING UNITS

UK BUSINESS SERVICES

Source: Ofgem

2.6.6 Figure 2-2 sets out how the total operating costs of NG have been allocated between

the forms of control in the HBPQ for 2004/05. This data has been taken from tabs 6.1 Opex 0405 and 6.2 UK Business Services of the HBPQ.



2.6.7 It should be noted that Figure 2-2 contains operating expenditure only, none of which is capitalised.

Figure 2-2: Allocation of total controllable and non-controllable operating costs to the forms of control

Shared services costs Transmission business

units costs

£m £m Controllable costs 313.3 Controllable costs 189.7 Non-controllable costs

86.6 Non-controllable

costs 767.3

Total 399.9 Total 957.0

Stage 1: Allocation between regulated and non-regulated businesses & exclusion of distribution network owners

Regulated 158 Non-regulated 241.7 Rounding 0.2 Total 399.9

Stage 2: Allocation between electricity (NGET) and Gas (NGG)

Electricity 119.9 Gas 38.1 Total 158.0

Stage 3: Allocation of costs to forms of control

Transmission business units costs by forms of control

Total Operating costs

ETO 87.9 + ETO 356.4 = 444.3 ESO 32.0 + ESO 335.5 = 367.5 Electricity Total 119.9 GTO 22.8 + GTO 145.8 = 168.7 GSO 15.3 + GSO 105.6 = 120.9 Gas Total 38.1 Non-transmission - + 13.6 = 13.6 Total (Electricity and Gas)

158.0 + 956.9 = 1115.1

Source: HBPQ data



2.6.8 We now summarise some of the components of total operating costs.

Shared services costs

2.6.9 Shared services costs are expenses incurred centrally which are not directly attributable to the transmission businesses. An allocation of these costs is charged to the four forms of control. The tables on the left hand side of Figure 2-2 show the stages by which the shared service costs are allocated first between the regulated and non-regulated businesses, then between the electricity and gas transmission businesses and then between the forms of control. Table 2-1 sets out the types of shared services and total costs allocated by them to the regulated businesses in the base year. These costs are allocated between the forms of control in stages 2 and 3 of Figure 2-2 above.

Table 2-1: Shared service costs 2004/05 allocated to transmission

Controllable

costs Non-controllable

costs Total

£m £m £m

Communications 2.9 0.2 3.1

Legal 2.6 0.0 2.6

Safety Health Environment 1.8 0.0 1.8

Regulation 1.6 12.1 13.7

Procurement & Logistics 7.3 2.4 9.8

HR and Scheme Trainees 9.7 0.3 10.1

Business Services Finance 3.2 0.0 3.2

Insurance 6.9 0.0 6.9

Audit 0.7 0.0 0.7

Property 18.3 0.0 18.3

IS 37.9 19.7 57.7

Operational Telecoms 17.2 0.0 17.2

Other 0.8 0.0 0.8

Corporate Centre 12.3 0.0 12.3

Total 123.2 34.7 158.0 Source: HBPQ data

2.6.10 The non-controllable costs of £12.1m in Regulation relate to transmission licence fees.

2.6.11 The non-controllable costs of £19.7m in IS relate to depreciation.

Transmission business unit costs

2.6.12 Transmission business unit costs are expenses directly attributable to the transmission businesses. Table 2-2 sets out the five transmission business units and the total costs associated with them across all forms of control in the base year. The table also shows the central adjustments made to arrive at the total transmission business unit costs. The tables on the right hand side of Figure 2-2 show how these transmission business unit costs are allocated between the forms of control.



Table 2-2: Transmission business unit costs 2004/05

Controllable

costs Non-controllable

costs Total

£m £m £m

Engineering Services 101.4 3.4 104.8

Network Strategy 30.4 172.2 202.6

Operations & Trading 38.3 381.9 420.2

Commercial 6.9 (14.0) (7.1)

Transmission Finance 4.1 0.0 4.1

Central Adjustments 8.6 223.8 232.4

Total 189.7 767.3 957.0

Source: HBPQ data

2.6.13 Table 2-3 shows a breakdown of the non-controllable costs included in Table 2-2.

Table 2-3: Non-controllable costs 2004/05

Depreciation Network

rates

Balancing services charge

Shrinkage and

storage costs

Other Total

£m £m £m £m £m £m

Engineering Services 2.7 - - - 0.7 3.4

Network Strategy 173.8 - - - (1.6) 172.2

Operations & Trading 2.1 - 303.1 75.9 0.8 381.9

Commercial - - - - (14.0) (14.0)

Transmission Finance - - - - - -

Central Adjustments 75.9 123.8 - - 24.2 223.8

Total 254.5 123.8 303.1 75.9 10.0 767.3

Source: HBPQ data and HBPQ “Other analysis”

2.6.14 At the bottom of Figure 2-2 the shared service costs and transmission business unit

costs are summed for each of the four forms of control.

Table 2-4: Controllable and non-controllable operating costs by forms of control in the base year

ETO ESO GTO GSO Non-

transmission Total

£m £m £m £m £m £m

Controllable costs 162.7 43.6 63.9 30.2 12.7 313.1

Non-controllable costs 281.6 323.9 104.8 90.8 0.9 802.0

Total 444.3 367.5 168.7 120.9 13.6 1,115.1

Source: HBPQ data

2.6.15 Table 2-4 sets out how the total operating costs by forms of control in Figure 2-2 are

split between controllable and non-controllable costs. This is also demonstrated in Figure 2-3 below which shows graphically the allocation of total operating costs for each form of control between controllable and non-controllable costs. The non-transmission costs are not included in the total operating cost by form of control but are required in order to reconcile to the total costs reported in the HBPQ.



Figure 2-3: Proportion of controllable and non-controllable operating costs in the base year

Source: HBPQ data

2.7 Year on Year Analytical Review of Total UK Transmission Operating Unit Costs

2.7.1 The following review compares the total controllable costs for the operating units of NG for the years 04/05 and 03/04. The principal purposes of the review is to identify any large movements in costs which may require further investigation, particular attention has been paid to large increases in costs in 04/05. The review is done on an aggregated basis in order to remove distortions due to year on year allocation to the different forms of control.

Table 2-5: Comparison of NG (UK Transmission) operating unit controllable costs between 2003/04 and 2004/05

2003/04 2004/05 Increase/

(decrease)

Controllable Costs Incurred £m £m £m

Net Staff Costs (including Agency Costs) 77.2 78.1 0.9

Materials 25.7 32.3 6.6

Subcontractors 30.1 27.7 (2.4)

Professional and consultancy fees 1.3 0.9 (0.4)

Non salary staff costs (including T&S2) 8.5 9.3 0.8

Insurance 9.8 10.7 0.8

Rents and buildings 2.3 1.7 (0.5)

Internal sales / purchases 140.5 148.3 7.8

Other (10.1) (8.6) 1.5

Total Accounting Controllable Costs 285.3 300.3 15.1

Non-transmission 12.7

Per Table 2-3 313.0

Source: HBPQ data

Net Staff Costs (including Agency Costs)

2.7.2 The reason staff costs are given net is due to capitalisation of labour costs of employees working on capital projects and transfer of salary costs between operating units in the transmission business. Note, these transfers are netted off by equivalent entries in the internal sales / purchases cost line and as such no further analysis of these costs is completed as the net effect on ECOC is nil.

2.7.3 Table 2-6 sets out a breakdown of the total Net staff costs including Agency costs in 03/04 and 04/05.

2 Travel & Subsistence

ETO

Controllablecosts

Non-controllablecosts

ESO GTO GSO



Table 2-6: Net Staff Costs including Agency Costs

2003/04 2004/05 Increase/

(decrease)

£m £m £m

Basic Wages & Salary 83.4 87.2 3.8

Overtime 5.1 6.2 1.1

Pension Costs 9.9 10.2 0.3

Capitalised Salaries (10.6) (12.1) (1.5)

Transferred Salary Costs (13.3) (16.4) (3.1)

Agency Costs 2.7 3.0 0.3

Total 77.2 78.1 0.9

Source: National Grid response to question DL1007

2.7.4 Basic wages and salary costs have increased by £3.8m or 4.6%. This increase has

been largely offset by the transfer of salary costs to other operating units and an increase in the level of costs capitalised. The increase was as a result of general wage inflation and a 2.7% increase in the number of FTEs. Increased capitalised salaries reflected the greater proportion of staff time spent on capital projects in 04/05 as compared to 03/04.

2.7.5 All other staff costs are in line with the prior period.

Materials

2.7.6 The main driver for the increase of £6.6m in materials costs is an £11.1m increase in material costs for the ETO Engineering Services operating unit. NG explained the increases as set out in Table 2-7.

Table 2-7: Breakdown of materials costs increases form 2003/04 to 2004/05

£m

Additional focus on site care activities 1.9

Additional costs of cable faults 1.9

Higher maintenance expenditure 1.2

Construction Scheme costs3 1.6

Subcontractor Costs booked to Materials 3.9

Other Increases 0.6

Total 11.1

Source: National Grid response to question OP1005

2.7.7 Our recommendations for the treatment of these cost increases in included in the

atypical and non-recurring items section below.

2.7.8 This increase in ETO materials costs was offset by a decrease in materials costs in the GTO of £4.2m.

Subcontractors

2.7.9 The subcontractors’ costs have decreased by £2.4m year on year. The actual movement in these costs is masked by cost transfers between categories. The decrease year on year is caused by the transfer of costs between the subcontractors and materials categories, hence the increase in materials costs and the decrease in

3 These costs are subsequently capitalised by a credit entry to ‘Other’ therefore do no represent increases in material operating expenses. No normalisation adjustment is required in respect of this amount as it is already removed from ECOC.



subcontractors. Once this movement has been taken out subcontractor costs are in line with the prior year, which reflects the similar levels of activity in both years.

Professional and consultancy fees

2.7.10 These costs are broadly in line with the prior year. These costs are incurred for a variety of reasons including planning, safety, health and environment projects.

Non-salary staff costs (including Travel & Subsistence)

2.7.11 These costs are in line with the prior year, which is as expected for an overall similar level of employees.

Insurance

2.7.12 Insurance costs have increased by £0.8m year on year. This increase is as a result of rising insurance premiums due to providers reassessing risks following 11th September 2001.

Rents and buildings

2.7.13 These costs have decreased by £0.5m to £1.7m year on year. Rental costs are generally decreasing for NG as a result of consolidation of the business following the merger.

Internal sales/ purchases

2.7.14 This balance has increased by £7.8m in comparison to the prior year. The balance consists of internal salary costs transferred between operating units as discussed above, internal purchases from related parties such as NGC Leasing, and allocations of cost between forms of control.

Other

2.7.15 The other category contains various adjustments including, credit entries to capitalise costs incurred as well as one off costs / credits such as compensation payments, consultancy services, stock provisions. As such the comparison of the balance year on year does not provide much insight.



2.8 Reconciliation of HBPQ to Statutory and Regulatory Accounts

2.8.1 This section provides a reconciliation from the operating costs in the HBPQ to audited statutory or regulatory accounts for 2004/05 so as to assess the consistency of the data provided in the HBPQ.

Electricity (NGET)

2.8.2 Table 2-8 sets out a reconciliation between the NGET regulatory accounts and the HBPQ for the base year. The regulatory accounts’ balances were taken from Note 1 to the accounts: Operating Costs. The HBPQ balances were taken from tab 6.1 Opex 0405 of the HBPQ and from the Other Analysis which accompanies the HBPQ.

Table 2-8: Reconciliation of NGET operating costs to regulatory accounts for 2004/05

Reg

accounts £m

HBPQ (ETO)

£m

HBPQ (ESO)

£m

HBPQ (total)

£m

Reconciling items

£m Depreciation 201.1 186 15.1 201.1 - Payroll costs 79.3 48.1 20.1 68.2 11.1 Rates 87.7 86.5 1.1 87.6 0.1 Balancing services incentive scheme direct costs

4

302.7 - 303.1 303.1 (0.4)

Other operating charges 140.7 123.7 28.1 151.8 (11.1) Total operating costs 811.5 444.3 367.5 811.8 (0.3) Source: Deloitte analysis

2.8.3 The payroll costs included in the table above under ETO and ESO are Net staff costs

(including agency costs), employee share option costs and pension deficit costs. The difference of £11.1m is net of shared services’ salaries, which are not split by form of control in the HBPQ (£16.5m), and agency costs which are not included in the payroll costs in the regulatory accounts (£5.4m). Details of these reconciling items were provided by NG.

2.8.4 The difference in balancing service incentive scheme direct costs arises because the balance in the regulatory accounts is shown net of prior year income of £0.4m. This income is not shown in the HBPQ.

2.8.5 The difference in other operating charges relates to differences in the reporting of shared services salaries & agency costs as discussed above.

2.8.6 The total difference of £0.3m is net of the difference on the balancing services incentive scheme direct costs of £0.4m and rounding of £0.1m.

Gas (NGG)

2.8.7 The operating costs in the NGG regulatory accounts include costs from both NGG’s regulated distribution and transmission businesses. As a result the regulated accounts do not reconcile to the HBPQ. Table 2-9 sets out how the total operating costs for NGG included in the HBPQ reconcile to the segmental analysis included in the NGG statutory accounts.

2.8.8 The segmental analysis in the statutory accounts of NGG gives the turnover and operating profit of the transmission business. The difference between these numbers is the operating costs balance. This is calculated in Table 2-9 below.

4 This balance is the major component of the ‘other’ non-controllable operating ESO costs reported in the HBPQ.



Table 2-9: Reconciliation of NGG operating costs to statutory accounts for 2004/05

£m

GTO Opex per HBPQ5 168.7

GSO Opex per HBPQ6 120.9

Total opex per HBPQ 289.6

Turnover per statutory accounts7 561.0

Operating profit per statutory accounts7 271.0

Total opex 290.0

Difference (due to rounding)8 0.4

Source: HBPQ data; NG accounts (see footnotes)

2.9 NG’s Adjustment to Accounting Operating Costs to Obtain ECOC

2.9.1 The following diagrams, Figure 2-4 to 2-6 demonstrate how NG has reconciled total operating costs for each form of control to ECOC. The total operating costs set out in the blue bars agree to those total operating costs included in Figure 2-2 and Figure 2-3 above. Reconciling items to be subtracted are shown as red bars. Reconciling items to be added are shown as black bars. ECOC is shown as a green bar.

2.9.2 Tables 2-10 to 2-13, set how the ECOC adjustments proposed by NG in Figure 2-4 to 2-7 compare to the numbers in the HBPQ. The differences between controllable costs in the HBPQ and controllable costs per the ECOC reconciliations have been discussed in detail in section 2.12.2 below.

2.9.3 All of the number includes in these Figures and Tables were provided by NG. Any adjustments to those numbers proposed by Deloitte are included in the sub-section entitled ‘Issues Arising from the Review of the HBPQ and the Reconciliation of HBPQ to ECOC’ which starts on page 43.

5 Source: HBPQ, tab 6.1 (Opex 0405), cell AF193 6 Source: HBPQ, tab 6.1 (Opex 0405), cell AF238 7 Source: NG Annual Report and Accounts 2004/05 8 NGG’s statutory accounts are rounded to the nearest million



Figure 2-4: Reconciliation of ETO Operating costs to ECOC for 2004/05

190.5

(0.4)

(12.1)

(86.5)0.2

5.5

4.511.9

1.2(9.7)

(168.4)444.3

0

50

100

150

200

250

300

350

400

450

500

Total Operating Costs

Depreciation &

amortisation

Pension deficit

(SSAP24)

Pension adjustm

ent

(FRS 17)

PLUGS adjustm

ent

Non-operational Capex

Provisions adjustm

ent

Fixed asset disposals

profit

Network rates

Transmission licence

Rounding

ECOC

£m

Source: Appendix 6 Part 1, Table 2.2_Ecoc.pdf as supplied by NG

Table 2-10: Reconciliation of ETO ECOC adjustments to HBPQ for 2004/05

ETO ECOC rec (Figure 2-4)

£m

HBPQ £m

Difference £m

Total operating costs 444.3 444.3 -

Removal of non-controllable costs:

Depreciation and amortisation (168.4) (168.4) -

Pension deficit (9.7) (9.7) -

Network rates (86.5) (86.5) -

Transmission licence (12.1) (12.1) -

PLUGS accounting costs (0.2) (0.3) 0.19

Other - (4.6) 4.6

Controllable operating costs 167.4 162.7 4.7

Include non-operational capex: 4.5 4.5 -

Other ECOC adjustments: 19.010

Rounding (0.4)

ECOC 190.5 Not stated

Source: Appendix 6 Part 1, Table 2.2_Ecoc.pdf as supplied by NG

9 This difference arises as a result of rounding. 10 The other ECOC adjustments of £19.0m is the sum of £12.1m PLUGS cash costs, £1.2m pension

adjustment, £5.5m provisions adjustment and £0.2m fixed asset disposal profit.



Figure 2-5: Reconciliation of ESO Operating costs to ECOC for 2004/05

367.5 (16.1)(2.9) (1.1)

2.0 349.4

0

50

100

150

200

250

300

350

400


Depreciation &

amortisation

Pension deficit (SSAP24)

Network rates


ECOC

£m

Source: National Grid, Response to question DL1094

Table 2-11: Reconciliation of ESO ECOC adjustments to HBPQ for 2004/05

ESO ECOC rec (Figure 2-5)

£m

HBPQ £m

Difference £m






Other - (303.8) 303.8



ECOC 349.4 Not

stated




Figure 2-6: Reconciliation of GTO Operating costs to ECOC for 2004/05

67.20.8

(10.3)

(36.1)1.3(0.6)(0.2)

(57.5)1.1168.7

0

20

40

60

80

100

120

140

160

180

Total O

perating Costs

Exceptional/ Atypical items

Depreciation &

amortisation

Pension deficit (SSAP24)

Pension adjustm

ent

(FRS 17)

Provisions adjustm

ent

Network rates


Non-operational C

apex

ECOC

£m


Table 2-12: Reconciliation of GTO ECOC adjustments to HBPQ for 2004/05

GTO ECOC rec (Figure 2-6)

£m

HBPQ £m

Difference £m






Transmission licence (10.3) (10.3) -

Other - (0.6) 0.6



Exceptional/ Atypical items 1.1

Other ECOC adjustments: 0.711



11 The other ECOC adjustments of £0.7m are a provision adjustment of £1.3m upwards, a pension

adjustment of £0.6m downwards.



Figure 2-7: Reconciliation of GSO Operating costs to ECOC for 2004/05

120.91.3 (14.2)

(0.2) (0.3) (2.5) 0.8105.8

0

20

40

60

80

100

120

140


Exceptional/ Atypical

items

Depreciation &

amortisation

Pension deficit

(SSAP24)

Pension adjustment

(FRS 17)

Provisions adjustment


ECOC

£m


Table 2-13: Reconciliation of GSO ECOC adjustments to HBPQ for 2004/05

GSO ECOC rec (Figure 2-7)

£m

HBPQ £m

Difference £m





Other - (76.4) 76.4



Exceptional/ Atypical items 1.3

Other ECOC adjustments: (2.8)12



12 The other ECOC adjustments of £2.8m are a provisions adjustment of £2.5m and a pension adjustment

of £0.3m.



2.10 Rationale for Adjustments

2.10.1 This section discusses NG’s rationale for the adjustments they have made in the ECOC reconciliations shown in Figures 3-4 to 3-7 above.

2.10.2 No amendments to these adjustments or additional adjustments are discussed at this stage of the report. This discussion is included in the section entitled ‘Issues Arising from the Review of the HBPQ and the Reconciliation of HBPQ to ECOC’ which starts on page 43.

Exceptional/ Atypical items

2.10.3 NG have added to operating costs the exceptional items included in the accounts to arrive at total costs which are then adjusted to ECOC. Table 2-14 shows what the exceptional items included in ECOC relate to. NG justified this treatment of the exceptional items with respect to merger and restructuring costs by stating that they were incurred to increase the efficiency of the business and therefore meet the definition of ECOC.

Table 2-14: Exceptional items included in ECOC in 2004/05

ETO £m

ESO £m

GTO £m

GSO £m

Total £m

Merger and restructuring costs - - 0.6 1.3 1.9

Distribution network sales costs - - 0.5 - 0.5

Total - - 1.1 1.3 2.4


2.10.4 Merger and restructuring costs arise as a result of the merger between National Grid Company Plc and Lattice Group Plc in October 2002.

2.10.5 Distribution network sales costs arise as a result of the sale of four of the eight gas distribution networks.

Depreciation and amortisation

2.10.6 NG is remunerated for depreciation through the RAV. Depreciation cost should therefore been removed from ECOC which NG has correctly done.

2.10.7 Amortisation is a non-cash cost and should also be removed from ECOC which NG have done.

2.10.8 The total depreciation and amortisation included in the HBPQ by forms of control in 2004/05 is made up as shown in Table 2-15:

Table 2-15: Depreciation and amortisation in 2004/05

ETO ESO GTO GSO

£m £m £m £m

Depreciation 186.0 15.1 61.7 14.2

Amortisation (17.6) 1.0 (4.2) -

Total 168.4 16.1 57.5 14.2

Source: HBPQ data and response to question DL1078

2.10.9 The depreciation costs are separately identifiable within the HBPQ whereas the

amortisation costs are included with the ‘Other’ non-controllable operating costs line of the HBPQ.

2.10.10 The negative amortisation balances arise as a result of the following:

• Amortisation of capital contributions: When a customer chooses to pay capital contributions the amount received is held on the balance sheet as a creditor. The



creditor is amortised to the income statement over the life of the underlying connection charges, effectively offsetting the depreciation charge for those connection assets13.

• Amortisation of termination receipts: Customers who terminate connection agreements with NG early are liable to compensate NG. It was agreed with NG’s auditors (PricewaterhouseCoopers) in 2004/05 that termination receipts are effectively capital contributions and that they should be amortised in the same way14.

2.10.11 The ETO amortisation of £17.6m is made up of £2.8m amortisation of capital contributions and £14.8m amortisation of termination receipts. It is worth noting that £14.8m represents an abnormally high level of termination receipts amortisation. This is because previous to 2004/05 termination receipts were not amortised. The decision to amortise them in 2004/05 necessitated a one-off catch up of amortisation15.

2.10.12 The GTO amortisation of £4.2m relates to amortisation of capital contributions16.

2.10.13 The NGG depreciation balances have been reconciled to the NGG statutory accounts in Table 2-16 below.

Table 2-16: Reconciliation of NGG depreciation costs to statutory accounts for 2004/05

£m

GTO depreciation per HBPQ17 61.7

GSO depreciation per HBPQ17 14.2

Total depreciation per HBPQ 75.9

Difference (due to rounding) 0.1

Depreciation per statutory accounts18 76.0

2.10.14 The NGET depreciation balances have been reconciled to the NGET regulatory accounts in Table 2-8 above.

Pension Deficit

2.10.15 In accordance with FRS 17, a pension charge arises due to movements in the pension deficit and actuarial differences. Since this is not a cash cost it is removed from total operating costs in order to arrive at ECOC. The NG adjustments included in the ECOC reconciliation above have been agreed to the costs included in the HBPQ. All pension deficit costs included in the HBPQ relating to the 4 forms of control have been removed from ECOC. Any further details regarding pension costs and adjustments are outside of the scope of this report.

Pension Adjustment

2.10.16 The pension adjustments made in the ECOC reconciliations relate to the non-cash element of the pension charge included within operating costs. This arises when the employers’ rate of contributions to a pension scheme differ from the rate determined by the scheme actuaries. Any further details regarding pension costs and adjustments are outside of the scope of this report.

13 Response to question DL1097 and OP1043

14 Response to question DL1097

15 Response to question DL1097 and OP1043


17 Source: HBPQ tables

18 Source: NGG 2004/05 Statutory Accounts



2.10.17 The pensions costs which remain in ECOC after these adjustments are detailed below. An assumption was required in order to approximate the amount of pensions cost allocated to each form of control as part of shared services costs. The total pensions cost for shared services can be seen in the Labour cost tab of the HBPQ.

2.10.18 This total cost has been allocated to the different forms of control by shared service and therefore the information on specifically how much of the allocation pensions cost is not available. The figures here take the total pensions costs for shared services (£8.7m) and split this according to the amount of shared service cost allocated to each form of control, removing the portion allocated to the non-regulated businesses. As such these amounts represent estimations rather than the actual costs by form of control.

Table 2-17: Pensions Costs included in ECOC for 2004/05

ETO £m

ESO £m

GTO £m

GSO £m

Directly booked in operating unit19 3.5 1.5 3.3 1.9

Adjusted to a cash basis (pensions adjustment)

20 1.2 - (0.6) (0.3)

Adjustment to a cash basis (provisions adjustment)

21 1.5 - - -

Allocated as part of shared service costs 1.9 0.7 0.5 0.3

Total 8.1 2.2 3.2 1.9

PLUGS adjustment

2.10.19 The PLUGS adjustment applies only to the ETO ECOC reconciliation. The adjustment arises as a result of the changes to electricity charging methodology which took effect on 1 April 2004. As a result of these changes NG were required to make repayments of connection charges made in advance by customers. In 2003/04 NG recognised an accrual for £22.5m in the accounts of NGET for these repayments. In 2004/05 NG made a further accrual of £0.2m and made cash repayments of £12.1m. Therefore the adjustment required in 2004/05 to adjust PLUGS to a cash basis is to remove the £0.2m accounting costs and replace it with the cash cost of £12.1m which gives a net adjustment of £11.9m.

2.10.20 Details of the adjustment to ECOC proposed by Deloitte in respect of PLUGS start on paragraph 2.14.10 below.

2.11 Analysis of NG’s non-operational capex


2.11.1 The following definition of non-operational capex has been used for the purposes of the price control;

2.11.2 Non-operational capex includes;

• Vehicles (including mobile plant and generators);

• Plant & machinery;

• Small tools & equipment;

• Office equipment;


20 Pensions adjustments in ECOC reconciliations, see Tables 4-7, 4-8, 4-9 and 4-10

21 Pensions adjustment in provisions movement, see Table 2-22



• Land and buildings used for administrative purposes; and

• IT (including telecoms).

2.11.3 Non-operational capex excludes;

• System assets; and

• Company cars.

2.11.4 NG have provided the following information regarding the non-operational capital expenditure over the previous price control period. It should be noted that this definition of non-operational capital expenditure was not used for the previous price control and therefore all of these costs were capitalised and included in the RAV with the exception of commercial vehicles.

2.11.5 NG have currently not provided sufficient detail to assign specific non-operational capital expenditure to forms of control. Therefore assumptions have been made to allocate this expenditure to specific forms of control.

Commercial Vehicles

2.11.6 Commercial vehicles reside in the field of engineering services within ETO. Accordingly these costs have been 100% allocated to ETO.

Plant and machinery, small tools and equipment and office equipment

2.11.7 NG state that the capitalised element of costs is likely to be immaterial as NG does not capitalise costs less than £2,000. Most of these items are therefore already included in operating costs.

Land and buildings used for administrative purposes

2.11.8 Operational land and buildings are generally purchased, capitalised and included with the Transmission RAVs. Certain operational lands are by necessity leased and their costs appear in Transmission operating costs are Operational rents.

2.11.9 Non-operational land and buildings are generally leased or purchases by a non-regulated property department and either:

• a lease cost is passed through to transmission operating cost; or

• a market based rent is charged to transmission operating costs.

2.11.10 There is an exception to this treatment which relates to the re-fit of buildings used for administrative purposes. The administrative centre in Northampton was purchased for £19m in the name of NGG with the cost capitalised as non-regulated capex. Market rent is charged to the regulated business as described above.

2.11.11 However, the initial capital expenditure on re-fitting the building for used was allocated to the business units occupying the building including the transmission business. These initial re-fit costs amounted to around £8.5m with £3m being allocated to transmission.

2.11.12 NG have not split this non-operational capex by form of control and have not stated which year it was incurred. Therefore the cost has currently been split between the forms of control equally and it is assumed the costs were incurred in 2004/05.

IT (including telecoms)

2.11.13 NG have provided historic data for the electricity business splitting out IT capital expenditure and giving a rough guide to whether these costs are operational or non-operational. It has been assumed that these costs relate to the ETO and ESO equally and therefore the cost of £2.3m for 2004/05 has been split equally between the two forms of control.



2.11.14 No historic data has been received for the gas transmission business.

Table 2-18: Non-operational capex included in ECOC for 2004/05

ETO £m

ESO £m

GTO £m

GSO £m

Commercial vehicles 2.5 - - -

Plant and machinery - - - -

Small tools & equipment - - - -

Office equipment - - - -

Land and building used for administrative purposes

0.8 0.8 0.8 0.8

IT (including telecoms) 1.2 1.2 - -

Total 4.5 2.0 0.8 0.8

Source: National Grid analysis

Provisions adjustments

2.11.15 The provisions costs included in the HBPQ are non-cash costs. They arise as a result of the application of accounting principles. Accounting costs in relation to provisions are incurred as soon as the entity has a constructive or legal obligation to pay such costs rather than when the cash payment occurs. In order to adjust ECOC to a cash basis the accounting provisions costs must be removed from ECOC and replaced with the cash costs paid in the year in relation to settling these obligations. Where the cash costs associated with provisions are one-off in nature they may then be excluded from ECOC on that basis.

2.11.16 Details of the adjustments to ECOC proposed by Deloitte in respect of provisions start on paragraph 2.13.5 below.

2.11.17 Appendix 1 shows a summary of the provisions analysis provided by NG. The analysis has been agreed to the statutory accounts of NGET and NGG on a total basis; it is not possible to check the allocations to the statutory accounts. The provision adjustments in the ECOC reconciliation are equal to the movement on provisions in Appendix 1 for each form of control as they should be.

2.11.18 It was noted that in NG’s original submission of the ECOC reconciliations the provision adjustments for GTO and GSO had been stated with the wrong sign i.e. where £1.3m should have been added to ECOC for GTO it had been subtracted and where £2.5m should have subtracted from ECOC for GSO it had been added. These errors have now been rectified giving an overall reduction to ECOC of £2.4m.

Fixed asset disposal profit

2.11.19 This adjustment applies only to the ETO ECOC reconciliation. The adjustment relates to sales proceeds on disposal of fixed assets. As a result of NG’s accounting treatment on the disposal of fixed assets any income on the sale is netted off of operating costs. In order that operating costs are not understated this income must be reversed out22. The balance has been agreed to the RAV analysis within the HBPQ (refer to tab 1.8.2, cell I30).

Network rates

2.11.20 Network rates are a non-controllable cost. As such they are passed directly on to the Transmission Business customers and so must be removed from total operating costs to arrive at ECOC. The adjustments included in the ECOC reconciliations have been




agreed to the costs included in the HBPQ. The total network rates included in the HPBQ for NGET have been reconciled to the regulatory accounts in Table 2-8 above.


2.11.21 Transmission licence fees are a non-controllable cost. As such they are passed directly on to the Transmission Business customers and so must be removed from total operating costs to arrive at ECOC. The adjustments included in the ECOC reconciliations have been agreed to the costs included in the HBPQ.

2.12 Issues Arising from the Review of the HBPQ and the Reconciliation of HBPQ to ECOC

Exclusion of non-controllable costs

2.12.1 In this section we discuss which non-controllable costs have not been removed from ECOC by NG and the implication of this.

2.12.2 In Figures 3-4 to 3-7 above NG have removed the following non-controllable costs from total operating costs in order to arrive at ECOC:

• Depreciation & amortisation

• Pension deficit

• Network rates

• Transmission licence

2.12.3 This however does not cover all of the non-controllable costs included in the HBPQ. Table 2-19 provides details of those non-controllable costs included in the HBPQ which were not removed from total operating expenses in the ECOC reconciliations i.e. those non-controllable costs which are included in ECOC. The totals in Table 2-19 agree to the differences in controllable operating costs between the ECOC reconciliations and the HBPQ as calculated in Tables 4-7 to 4-10 above.

Table 2-19: Non-controllable costs included within ECOC by NG

ETO £m

ESO £m

GTO £m

GSO £m


- 303.1 - -

Shrinkage - - - 58.4

Storage costs - - - 17.5

Excluded services costs 1.1 - - -

Employee share option scheme costs 3.3 0.7 0.6 0.5

Other 0.3 - - -

Total 4.7 303.8 0.6 76.4

Source: HBPQ data and response to question DL1078


2.12.4 Balancing service costs relate to the electricity transmission business only. These costs are paid to power stations to increase their energy supply and to large energy users to reduce their energy demand in order to balance the network. This cost is remunerated through external ESO schemes and so should be excluded from ECOC for the purposes of the price control review. The make up of this cost is outside of the scope of this report. However the cost has been reconciled to the NGET regulatory accounts in Table 2-8 above.



Shrinkage and Storage costs

2.12.5 Shrinkage and storage costs are costs incurred in operating the gas network. At present these costs are remunerated through the GSO incentive schemes so have been excluded from ECOC for the purposes of this report.

Excluded services costs

2.12.6 Excluded services are defined in the Transmission Operators Special Licence Condition.

2.12.7 NG have stated that the £1.1m of excluded services costs disclosed in tab 6.1 of the HBPQ are all the excluded service costs included in 2004/05 operating costs23.

2.12.8 The treatment of excluded service costs are outside of the scope of this report. For the purposes of this report they have been removed from ECOC.

Employee share option scheme costs

2.12.9 These costs appear in the HBPQ in 2004/05 only. These costs arise for the first time in the base year because during 2004/05 NG adopted FRS20 ‘Share Based Payments’. The standard requires that where shares or rights to shares are granted to third parties, including employees, a charge should be recognised in the profit and loss account based on the fair value of the shares or options at the date the grant of shares or right to shares is made.

2.12.10 NG have confirmed that these solely relate to the fair value of the shares at the grant date and as such are non-cash costs for the NG group. NG further noted that these costs are charged to NGET by NG and as such are a cash cost to NGET.

2.12.11 Since these costs are not remunerated as pass through items or through the RAV it is fair to say that they should not be excluded from ECOC on the basis of management having classified the costs as non-controllable in the HBPQ. However these costs result from the application of an accounting standard and do not represent a cash cost to NG.

2.12.12 Since these costs have not arisen previously they is currently no system of remunerating them in place. Ofgem will therefore have to take a view as whether to include them in ECOC or to set up an alternative method of remuneration.

Other

2.12.13 The other non-controllable costs included in ECOC are immaterial and on this basis they have not been investigated further for the purposes of this report.

Conclusion

2.12.14 Table 2-20 summarises the proposed adjustment arising from our review of non-controllable costs.

2.12.15 Balancing services incentive scheme direct costs and storage and shrinkage costs have been identified separately since whilst they should be removed from ECOC they should be remunerated elsewhere.




Table 2-20: Proposed ECOC adjustments

ETO £m

ESO £m

GTO £m

GSO £m

Costs to be removed from ECOC:

Excluded services costs 1.1 - - -

Employee share option scheme costs 3.3 0.7 0.6 0.5

Total 4.4 0.7 0.6 0.5

Costs remunerated elsewhere and thus should be removed from ECOC:

Balancing services incentive scheme direct costs - 303.1 - -

Shrinkage - - - 58.4

Storage costs - - - 17.5

Total - 303.1 - 75.9


2.13 Cash versus non-cash items

2.13.1 This section deals with costs included in the HBPQ which arise as the result of accounting standards rather than cash payments. In order that ECOC is stated on a cash basis these accounting costs must be removed and replaced with the associated cash costs.

2.13.2 The meaning of cash has been interpreted as costs that are settled in cash rather than strictly cash paid during the year. The significance of this is that no adjustments have been made in respect of prepayments, creditors or accruals movements as these derive from short term timing differences rather than cash, non-cash distinction.

2.13.3 If a strict “cash paid during the year” definition of cash costs was used, the accounting entries impacting operating expenses within these captions would need to be removed from ECOC and replaced these with the cash costs paid in the year in respect of operating costs.

2.13.4 Appendix 2 shows details of the adjustments that would be required if the strict cash definition was adopted. We do not recommend that adjustments are made to ECOC for these short term timing differences.

Provisions adjusted to a cash basis

2.13.5 Provisions’ costs do not represent cash costs incurred by the business. Accounting costs in relation to provisions are incurred as soon as the entity has a constructive or legal obligation to pay such costs rather than when the cash payment occurs. In order to determine cash costs we need to remove the accounting provisions’ costs and replace these with the cash costs paid in the year in relation to settling these obligations. The net effect of removing accounting costs and replacing them with cash costs is to adjust ECOC for the movement on the provisions in the year.

2.13.6 It should be noted that where provisions arise as the result of an atypical or non-recurring cost to the business the cash costs should not be added into ECOC since these are not ongoing cash costs of the business.

2.13.7 Appendix 1 shows the provisions’ analysis provided by NG. In respect of that analysis NG have made the following adjustments to ECOC as shown in Table 2-21.



Table 2-21: NG provisions to a cash basis adjustments to ECOC 2004/05

ETO £m

ESO £m

GTO £m

GSO £m

Adjustment to increase/ (decrease) ECOC

5.5 - 1.3 (2.5)

Source: response to questions DL1004 and DL1041

2.13.8 Table 2-22 sets out a summary of the analysis in Appendix 1 to show how the

adjustment of £5.5m proposed by NG is made up. The accounting costs are subtracted from ECOC and the cash costs are added in. It should be noted that all costs in Table 2-22 are expressed as positive numbers and so the total accounting costs of £2.0m are in fact a credit to operating expenses and thus are added to ECOC rather than subtracted.

Table 2-22: NG ETO provision analysis 2004/05

Accounting

Costs £m

Cash costs £m

NG Adjustment

£m

Merger and restructuring - 1.6 1.6

Pension (1.5) - 1.5

Environmental (0.5) 0.5 1.0

Other - 1.4 1.4

Total (2.0) 3.5 5.5

Source: response to question DL1041

2.13.9 The cash costs of £1.6m added into ECOC in respect of the merger and restructuring provision are an exceptional expense. They do not represent the ongoing cash costs of the business and so should be removed from ECOC. The removal of the £1.6m of exceptional costs is included in Table 2-25 below which summarises any proposed adjustments arising in the cash versus non-cash items section of the report.

2.13.10 The adjustments relate to the non-cash element of the pension charge included within operating costs and therefore has been correctly removed from ECOC. Table 2-17 provides details of pensions costs remaining within ECOC.

2.13.11 The £0.5m accounting cost relating to the Environmental provision is a provision release to the P&L. This occurs when too high a provision is made in previous years and so the provision is reduced by crediting the P&L. The effect on operating costs of this is that operating costs are made too high in the years the provision was made and are reduced in the year it is released. Therefore NG’s treatment of adding back the release of the provision to remove the effect of operating costs being reduced is correct.

2.13.12 The £0.5m of environmental provision utilisation in 2004/05 relates to cleaning up past contamination. The level of expenditure for this type of work is driven by legal obligations and the condition of NG’s sites. This cash cost has been removed from ECOC in order to highlight the item. Ofgem will need to take a view on whether to remunerate NG for environmental remediation.

2.13.13 The other cash costs of £1.4m relate to payments of onerous lease costs in respect of the Brookmead property in Guildford. Brookmead was vacated during 2001/02 as part of the consolidation of National Grid’s regional offices through the Refocusing the business initiative. The £1.4m represents ongoing annual cash costs until 2015 in respect of a 25 year lease signed in 1990, with no break clauses.

2.13.14 The decision to vacate the property was taken in order to facilitate cost savings and the building has been sublet for a period from June 2004 to October 2015. The cash costs



of the onerous lease could therefore be covered by income from the sublet property and as such the cash costs have been removed from ECOC.

2.13.15 Similar analysis to that included in Table 2-22 for ETO is set out in Tables 4-18 and 4-19 for GTO and GSO respectively.

Table 2-23: GTO provision analysis 2004/05

Accounting Costs £m

Cash costs £m

Adjustment £m

Merger and restructuring 0.9 2.2 1.3

Total 0.9 2.2 1.3


Table 2-24: GSO provision analysis 2004/05

Accounting Costs £m

Cash costs £m

Adjustment £m

Merger and restructuring 1.3 3.1 1.8

Other 4.3 - (4.3)

Total 5.6 3.1 (2.5)


2.13.16 The adjustment for the merger and restructuring provision accounting costs of £0.9m

GTO and £1.3m GSO correctly remove the exceptional expenses that have been added to ECOC per Table 2-14 above. There is a difference of £0.3m between the GTO costs in Table 2-14 and Table 2-24. This is because of the total accounting cost of £0.9m; £0.6m was included in the accounts as an exceptional cost and the remaining £0.3m as an operating cost.

2.13.17 The cash costs of £2.2m for GTO and £3.1m for GSO added into ECOC in respect of the merger and restructuring provision are exceptional expenses. They do not represent the ongoing cash costs of the business and so should be removed from ECOC.

2.13.18 The accounting cost of £4.3m in respect of GSO other provisions relates to NGG’s obligation to deliver EU Emissions Trading Scheme Emissions Allowances. NG burns natural gas in order to run compressors which produces CO2. As a result NG has an emissions liability. This cost is one which will be settled in cash and is recurring, accordingly the cost has been added back into ECOC. NG has stated that cash payment of this amount will be made during 2006.

Creditors, Accruals and Prepayments

2.13.19 Similar to provisions, creditors and accruals do not represent cash costs paid during the accounting period by the business. However these are costs which will be paid with cash and so any movements in the year end balances are purely a result of short term timing differences. For the purposes of this report these short term timing differences have been ignored. An analysis prepared on a actual cash basis is provided in Appendix 2.



Conclusion

2.13.20 Table 2-25 summarises the proposed ECOC adjustments arising from the above analysis of cash versus non-cash items.

Table 2-25: Proposed ECOC adjustments resulting the review of cash versus non-cash items

ETO £m

ESO £m

GTO £m

GSO £m

Remove restructuring exceptional costs (1.6) - (2.2) (3.1)

Remove environmental clean up costs (0.5) - - -

Remove onerous lease costs (1.4) - - -

Add back carbon emission costs - - - 4.3

Total (3.5) - (2.2) 1.2

Source: Deloitte Analysis

2.14 Atypical and non-recurring items

2.14.1 This section discusses some of the unusual and one-off items included within operating costs in the base year. In order that ECOC represents the continuing costs of the business these may have to be removed.

Exceptional restructuring and reorganisation costs

2.14.2 As noted in paragraph 2.10.3 and Table 2-14 above, NG have added to ECOC for GTO, £0.5m of exceptional costs relating to the sale of the distribution network businesses. This is a non-recurring atypical item and should be removed from ECOC for the purposes of the price control review.

2.14.3 NG have also stated24 there are further atypical costs relating to distribution sales of £0.2m in the GTO as well as a net amount of £0.1m in the GSO. This £0.1 is made up of £0.4m atypical costs offset by a £0.3m atypical credit relating to the release of a provision. These amounts have also been removed from ECOC.

2.14.4 Table 2-14 also shows that £1.9m of exceptional merger and restructuring costs were added to ECOC by NG (£0.6m in GTO and £1.3m in GSO). These costs arise when provisions are made and so are an accounting cost. Because NG have adjusted their provisions to a cash basis these costs were removed from ECOC (paragraph 2.13.16).

2.14.5 Included within the ETO operating costs in the HBPQ for 2004/05 are £0.1m of severance costs relating to the restructuring of the business. This is not an ongoing cash cost to the business and should be removed from ECOC.

2.14.6 NG have stated that there are no further costs included in the HBPQ for 2004/05 for the electricity transmission business relating to reorganisation, restructuring or the merger.

Efficiency costs

2.14.7 In the HBPQ 2004/05 other controllable costs include £3.5m of ‘investment for efficiency’ costs. These costs relates to consultancy support associated with the “Ways of Working” Review.

2.14.8 The “Ways of Working” review was initiated in order to resolve the outstanding barriers to realising the benefits of a modernised field force. Workshops were conducted with the entire NG field force in order to capture an accurate view of the areas for attention. A series of improvements were then rolled out across the country

25.

24 Source: Answer to DL1129

25 Source: Paragraph 116 of the Executive Summary to the HBPQ



2.14.9 Since this is not a recurring expense it should be removed from ECOC. Of the £3.5m of costs included in the HBPQ £3m relates to ETO and the remaining £0.5m to GSO.

PLUGS

2.14.10 Details of PLUGS are given in paragraph 2.10.19 above. In respect of PLUGS NG have made an adjustment to increase the ETO ECOC by £11.9m. The PLUGS costs are not an ongoing cost to the business and as such they should not be included in ECOC. Furthermore it was noted in NG’s response to our questions regarding PLUGS that “Ofgem allowed NG to recover these payments [in relation to PLUGS] through changes to charges from 1st April 200426”. On this basis it would not seem unreasonable to remove NG’s PLUGS costs from ECOC.

2.14.11 As noted in paragraph 2.10.19 the £11.9m adjustment made by NG in respect of PLUGS is net of removing accounting costs of £0.2m and replacing them with cash costs of £12.1m. The accounting costs should be removed since they are not an ongoing cost to the business and so no adjustment is required in respect of them. On the same basis the £12.1m cash costs should also be removed and so ECOC needs to be adjusted by this amount.

Subsidence repair costs

2.14.12 The network strategy costs for ETO include £0.6m for emergency subsidence repairs at the Littlebrook substation. This is not a continuing cost and so an adjustment should be made for this in order to normalise costs in the base year27.

Material costs

2.14.13 Material costs for engineering services increase by £11.1m from £14.4m in 2003/04 to £25.5m in 2004/05 for Electricity TO. When asked the reason for this NG provided the following breakdown of the increase28:

• £1.9m: additional focus on site care activities including the roll out of national outsourced contracts for statutory testing such as mechanical, electrical and legionella tests;

• £1.9m: additional costs of cable faults;

• £1.2m: higher levels of planned and unplanned expenditure on maintenance and repairs to high voltage primary plant, in particular, higher costs incurred on supergrid transformers;

• £1.6m: certain costs associated with construction schemes are incurred on the Materials line in the Engineering Services management accounts and subsequently transferred to Construction by way of a credit entry to a separate Cost-Offsets line in the Engineering Services management accounts and so does not represent a real movement in Materials costs;

• £3.9m: certain costs relating to Engineering Services capital expenditure are initially coded to the Materials line owing to the configuration of our financial systems which are subsequently transferred to the balance sheet through a credit entry to the Subcontractors line and therefore do not represent real movements in Materials (or Subcontractors) costs; and

• £0.6m: other increases.



28 Response to question OP1005



2.14.14 The top three items which total £5m appear to relate to atypically high levels of costs. An adjustment to ECOC in respect of these costs may be required in order to achieve a normalised cost base in the base year.

2.14.15 These other movements do not represent real year on year cost increases as the costs are subsequently capitalised. No normalisation adjustment is required in respect of these costs.

Control centre rationalisation costs

2.14.16 During 2004/05 the gas Area Control Centres were rationalised to a single site at Hinckley in order to deliver cost savings going forward. Non-recurring operating costs of £2.4m were incurred as double manning was provided during the period of transition between live control rooms and as staff were relocated. These costs are included with the Operations and Trading costs for the GSO form of control in the HBPQ29.

Conclusion

2.14.17 Table 2-26 summarises the proposed adjustments arising from our analysis in respect of exceptional and non-recurring items.

Table 2-26: Proposed ECOC adjustments in respect of exceptional and non-recurring items

ETO £m

ESO £m

GTO £m

GSO £m

Network sales costs - - (0.7) (0.1)

Severance costs (0.1) - - -

Investment for efficiency costs (3.0) - - (0.5)

PLUGS (12.1) - - -

Littlebrook subsidence repairs (0.6) - - -

Atypical materials costs (5.0) - - -

Control centre rationalisation costs - - - (2.4)

Total (20.8) - (0.7) (3.0)


2.15 Capitalisation Policy

2.15.1 In this section we discuss the impact of capitalisation policy on the cost base on NG. Even within the boundaries of accounting standards there are areas of judgement involved with capitalisation of costs such that they remain subjective. This subjectivity arises from the way in which overhead costs are determined to be directly attributable to capital projects and therefore capitalised.

Cost capitalisation

2.15.2 Cash payments in the base year are either classified as capital expenditure and booked on the balance sheet of NG or classified as operating expenditure and booked in the profit and loss account for that year. Ofgem has noted that it may be in NG’s interest to capitalise costs as the incentive rate is greater for capex than for opex.

2.15.3 As part of the recent distribution price control review a range of capitalisation policies was revealed for the 14 distribution network operators (DNOs) in relation to the capitalisation of overhead costs. This range of policies resulted in similar costs being treated differently within the DNOs.

29 Source: Paragraph 59 of Appendix 3 to the HBPQ



2.15.4 Ofgem noted that capitalisation policy was an issue for the previous price control review and therefore the capitalisation policies of NG with respect to overheads have been examined and are discussed below.

2.15.5 In order to determine whether NG was generally capitalising a large proportion of costs as compared to the DNOs the following evaluation has been undertaken.

2.15.6 Figure 2-8 shows the percentage of total costs capitalised for all of the UK transmission and distribution companies. The percentage of capex to capex plus opex (excluding depreciation) was calculated using the regulatory accounts for the 5 years from 2000/01 to 2004/05 for each of the companies. The capex balance was taken to be additions to fixed assets net of any capital contributions. The opex balance was taken to be the sum of cost of sales, administrative expenses and distribution costs including any exceptional items less depreciation. An average of the percentage of capex to opex was then taken over the five years.

Figure 2-8: Bar chart showing average percentage of total costs capitalised over the last 5 years for UK transmission and distribution companies.30

-20.0%

10.0%

40.0%

70.0%

NGG

SHETL

NGET

CN East

SHEPDL

CN W

est

LPN

YEDL

S W

ales

SPN

NEDL

SPD

EPN

SPT

S W

est

SP M

an

UU

% of total costs capitalised

NG companiesTransmission companiesDistribution companies

Key to the companies included in Figure 2-8:

NGG: National Grid Gas Plc SHETL: Scottish Hydro-Electric Transmission Limited NGET; National Grid Electricity Transmission Plc CN East: Central Networks East Plc SHEPDL: Scottish Hydro-Electric Power Distribution Limited CN West: Central Networks West Plc LPN: EDF Energy Networks (LPN) Plc YEDL: Yorkshire Electricity Distribution Plc S Wales: Western Power Distribution (South Wales) Plc SPN: EDF Energy Networks (SPN) Plc NEDL: Northern Electric Distribution Limited SPD: SP Distribution Limited EPN: EDF Energy Networks (EPN) Plc SPT: SP Transmission Limited S West: Western Power Distribution (South West) Plc SP Man: SP Manweb Plc UU: United Utilities Electricity Plc

30 Source: Regulatory accounts from 2000/01 to 2004/05 for UK transmission and distribution companies



2.15.7 The NGG percentage included in Figure 2-8 is in respect of its total transportation business i.e. transmission and distribution. No split between transmission and distribution is given in the NGG regulatory accounts. Figure 2-8 indicates that NGG capitalises a relatively low percentage of its total costs in comparison to other UK distribution and transmission companies.

2.15.8 NGET capitalises a larger percentage of its total costs than NGG. The disparity between the two NG companies may be due to the differing nature of the operations. There is nothing in the above analysis to suggest than NGET is over capitalising costs.

2.15.9 It is noted that both NGET and NGG capitalise a lower proportion of expenditure than all of the DNOs. This provides some assurance that NG does not adopt accounting policies with a bias towards capitalisation.

2.15.10 Examination of NG’s accounting policies and further questioning supports the position that NG capitalise proportionally lower costs than the DNOs. Some of the DNOs use cost absorption models in order to allocate overheads to capital projects and thus increase the amounts of capitalised costs.

2.15.11 NG does not use these types of costs models to allocate overheads to capital projects, with the main costs being capitalised (apart from asset purchase costs) being the labour costs associated with employees working on a specific capital project. This capitalisation of labour costs is in line with accounting standards and is discussed in more detail below.

2.15.12 In summary this analysis supports the view that NG adopt more conservative cost capitalisation policies than the DNOs.

Capitalisation of labour costs

2.15.13 NG capitalises the labour costs associated with the construction of specific assets. These costs are captured by the use of a time-writing system which allows the employees’ time to be recorded against a specific work order which will be capital expense or operating expense in nature.

2.15.14 The table below shows the total amounts of labour costs by form of control as well as the amounts capitalised in each for the base year.

Table 2-27: Labour costs capitalised in the base year

ETO ESO GTO GSO

£m £m £m £m

Total Capitalised Salary Costs 8.6 - 1.5 2.0

Total Salary Costs 58.4 16.5 18.2 10.5

% Capitalised 15% 0% 8% 19%

Source: Answer to DL1007 and HBPQ

2.15.15 It is noted that for each form of control the amount of labour costs capitalised is less

than 20%. This level of capitalisation is low in comparison to the levels of costs being capitalised by the distribution companies and supports the overall assertion that NG capitalises a lower proportion of costs than the other transmission distribution companies.

2.15.16 For ETO, capitalised labour costs amount to £8.6m or 15% of the total labour costs for the form of control. The labour costs capitalised occur in the Engineering Services and Network Strategy operating units which is in line with the expectation that capital projects would be completed within these business units. It is noted that no costs are capitalised in respect of labour costs of the commercial and transmission finance operating units are capitalised as these operating units do not complete capital projects.



2.15.17 For ESO, no labour costs are capitalised as all activity within the form of control is operating in nature.

2.15.18 For GTO, capitalised labour costs amount to £1.5m or 8% of the total labour costs for the form of control. This represents a lower level of capitalisation than the ETO, but as the same timewriting mechanism exists for the capitalisation of salary costs for both forms of control, the conclusion is that fewer capital work orders are carried out in the GTO than the ETO.

2.15.19 For GSO, £2m of salaries are capitalised, in contrast to the electricity SO. The costs capitalised relates to the Gemini & iGMS projects. These were the capital projects where O&T business unit resources were used in 2004/05. The staff members on these projects were 100% dedicated to the delivery of these capital projects and hence their costs have been capitalised.

2.15.20 Indirectly attributable costs generally relate to overheads and salaries of support functions. NG has stated that the capitalisation rates used reflect the cost of employing the staff concerned. The rates cover salaries and associated employment costs plus any directly attributable costs such as travel and subsistence. The rate does not include any of the general overheads of the business.

2.15.21 Included in these types of costs are the shared services costs, these are expenses incurred centrally which are not directly attributable to the transmission businesses. The cost centres within these costs are: Communications, Legal, Safety Health Environment, Regulation, Procurement & Logistics, HR and Scheme Trainees, Business Services Finance, Insurance, Audit, Property, IS, Operational Telecoms and Corporate Centre.

2.15.22 We have found no evidence of capitalisation of these costs within NG.

IT Cost Capitalisation

2.15.23 NG has a detailed IT cost capitalisation guidance, held in the finance manual. This

details the types of costs to be capitalised, both software and hardware, as well guidance over the labour costs to be capitalised.

2.15.24 Following the merger National Grid agreed to adopt common policies with respect to IT costs. As a consequence of this change in policy IT development costs previously treated as operating costs within National Grid Gas were capitalised. The revised rules were implemented from 1 April 2003. In 2004/05 £63.8m of IS costs were capitalised. This represents 35% of the total IS costs (excluding depreciation) of £184.4m. The capitalised IS costs of £63.8m include £7.9m relating to IS project development costs capitalised as a result of the new policy. Hence an additional 4% of total IS costs (excluding depreciation) have been capitalised31.

2.15.25 The new IT cost capitalisation policy, including the capitalisation of software development, is in line with FRS 15 and therefore no adjustment is proposed in respect of these costs.

Non-operational capital expenditure

2.15.26 Non-Operational Capital Expenditure is not an accounting concept but one defined by Ofgem in the context of Price Controls. This type of expenditure is capitalised and put on the entity’s balance sheet from an accounting standpoint. In the context of the Price Control this type of capital expenditure is treated as operating expenditure i.e. the expenditure is not included in the RAV but included in the Price Control calculation. The effect of this is that NG does not receive a return on non-operational capital




expenditure in the same way it does on regulatory assets, but is allowed higher revenues through increased prices to compensate for this expenditure.

Commercial Vehicles

2.15.27 NG have appropriately removed the commercial vehicles costs from capital expenditure and added these back to ECOC.

Plant and machinery, small tools and equipment and office equipment

2.15.28 NG state that the capitalised element of costs is likely to be immaterial as NG does not capitalise costs less than £2,000. This assertion appears reasonable and therefore no adjustment is proposed in respect of these costs.

Land and buildings used for administrative purposes

2.15.29 It is NG’s view that their treatment is in line with Ofgem requirements and no adjustment to RAVs would be appropriate. As the non-operational items are not included in the regulated business and the cost of occupying these buildings is passed through to the regulated business as an operating cost this assertion seems reasonable. It should be noted that the cost charged to the regulated business by the property company is a related party charge and is referred to in paragraph 2.17.8.

2.15.30 There is an exception to this treatment which relates to the re-fit of buildings used for administrative purposes. NG have correctly suggested that this cost of £3.2m should be removed from the RAV and added back to ECOC. Deloitte have made the assumption the cost was incurred equally in each forms of control.

IT (including telecoms)

2.15.31 NG have provided historic data for the electricity business splitting out IT capital expenditure and giving a rough guide to whether these costs are operational or non-operational. Deloitte have made the assumption that the expenditure was incurred equally in ETO and ESO to allocate the cost of £2.4m to the forms of control

2.15.32 No historic data has been received for the gas transmission business.

2.15.33 The following table shows the amounts of non-operational capital expenditure included in ECOC.

Table 2-28: Non-operational capex included in ECOC

ETO £m

ESO £m

GTO £m

GSO £m

Commercial vehicles 2.5 - - -

Plant and machinery - - - -

Small tools & equipment - - - -

Office equipment - - - -

Land and building used for administrative purposes

0.8 0.8 0.8 0.8

IT (including telecoms) 1.2 1.2 - -

Total 4.5 2.0 0.8 0.8

Source: National Grid Analysis

Conclusion

2.15.34 Our analysis included above does not identify that NG has been over capitalising overheads. NG appears to have appropriately added back non-operational capex to ECOC and no adjustments are proposed. Discussions are continuing between NG and Ofgem regarding which types of expenditure are considered non-operational capex. If



the classification of costs is changed, an adjustment to the amounts reported above may be required. The responsibility for the finalisation of these figures lies with Ofgem.

2.16 General Accounting Principles

2.16.1 This section deals with the impact of changes to general accounting principle on ECOC, principally the adoption of IFRS.

International Financial Reporting Standards

2.16.2 With effect from 1 April 2005, NG is required to report its consolidated financial results in accordance with International Financial Reporting Standards (IFRS). The first results published under IFRS covered the six month period ending 30 September 2005 and the first set of full financial statements to be published under IFRS will cover the year ending 31 March 2006.

2.16.3 Consequently, throughout the price control period 2007-2012 NG will report under IFRS, however the HBPQ uses information in accordance with UK Generally Accepted Accounting Principles (UK GAAP). This section of the report is intended to provide a focused analysis of the types of changes which impact operating expenses as a result of the adoption of IFRS.

2.16.4 The base information for this analysis was the NG IFRS Conversion Statement published on 28 July 2005. The Conversion Statement (CS) presents the impact of conversion from UK GAAP to IFRS on the consolidated financial statements for the year ended 31 March 2005. The information in this statement is not presented by form of control but does give detail on a segmental basis, which shows UK electricity and gas transmission separately. Accordingly, where appropriate, this level of detail has been used to determine the impact on the transmission business of NG.

Overall impact on National Grid Plc

2.16.5 Under UK GAAP profit for the year before minority interests was £907m32. After the effect of IFRS measurement and presentation adjustments the profit for the year under IFRS - continuing operations amounts to £1,120m32, an increase of £213m. Net assets under UK GAAP amounted were £1,391m33 whereas under IFRS net assets were £2,095m33, a difference of £704m.

2.16.6 These increases in profit and net assets are relatively large in the context of NG representing an increase of 23% in profit terms and 51% in terms of net assets. However although these adjustments are large, the vast majority of the adjustments do not relate to the UK transmission business.

2.16.7 As can been seen from the segmental analysis within the CS, for the UK electricity and gas transmission segment, the operating profit before exceptionals and goodwill amortisation is £809m34 under UK GAAP and £817m34 under IFRS, a difference of £8m. As revenues for the segment are unchanged at £1,930m34 under both UK GAAP and IFRS is can be deduced that the level of costs is similar under UK GAAP and IFRS.

2.16.8 The segmental analysis also shows the effect of the adoption of IFRS on the total assets and total liabilities of the UK electricity and gas transmission segment. Total assets under UK GAAP are £6,448m35 as opposed to £6,444m35 under IFRS, a difference of £4m. Total liabilities for the segment under UK GAAP amount to £713m35, however under IFRS amount to £1,316m35. This difference of £603m primarily relates

32 Source: NG IFRS Conversion Statement, p7






to the recognition of net pension liabilities. Under UK GAAP, these liabilities were disclosed but were not recognised. On adoption of IFRS net pensions liabilities were recognised with corresponding entries to opening reserves.

Impact on controllable operating costs

2.16.9 The impact of the conversion from UK GAAP to IFRS on operating costs is given in note 536 within the conversion statement and is as follows.

Table 2-29: Impact of the conversion from UK GAAP to IFRS on controllable operating costs

IFRS IFRS

measurement presentation

UK GAAP adjustments adjustments IFRS

£m £m £m £m

Depreciation 860 129 - 989

Amortisation 272 (266) - 6

Payroll Costs 941 60 50 1,051

Other Operating Charges -

- Purchases of electricity 1,678 182 - 1,860

- Purchases of gas 385 - - 385

- Rates and property taxes 490 - - 490

- Electricity transmission services scheme direct costs

301 - - 301

- Replacement Expenditure 474 (474) - -

- Other operating charges 1,275 (331)

(50) 894

Total operating costs 6,676 (700) - 5,976

Source: National Grid IFRS Conversion Statement

Depreciation

2.16.10 Under IFRS, depreciation increased by £129m over the whole NG. The reason for this is a difference in the accounting treatment of replacement expenditure (repex). Repex represents the cost of replacing gas mains and service assets and under UK GAAP, repex is recognised in the profit and loss account as incurred. Following NG’s adoption of IFRS, repex is capitalised and depreciated over its useful economic life.

2.16.11 When specifically considering the UK Electricity and Gas Transmission business, we note that the adjustment to fixed assets regarding repex only amounts to an £8m increase and this amount will be spread across the useful lives of the repex assets. Accordingly we do not expect this change in accounting policy to materially affect the depreciation charge in the transmission business.

2.16.12 In addition, depreciation is not a controllable cash cost and therefore does not have an impact on the controllable cash costs.

Amortisation

2.16.13 Under IFRS, the amortisation charge for the year decreased by £266m for the NG group. The reason for this is a difference in the accounting treatment of goodwill.




Under UK GAAP goodwill arising on business combinations is amortised over a period of 20 years. Under IFRS, goodwill is not amortised, but tested for impairment annually.

2.16.14 In addition, amortisation is not a controllable cash cost and therefore does not have an impact on the controllable cash costs.

Payroll Costs

2.16.15 Under IFRS, payroll costs increases by £110m for the NG Group. Of this amount £50m is a presentation adjustment with the corresponding entry disclosed in Other operating charges under UK GAAP. As both of these entries are within operating costs these presentation adjustments do not have any effect on the overall level of operating costs.

2.16.16 The remaining £60m increase relates to a non-recognition of regulatory assets in the US (£58m) as well the recognition of a provision for untaken holiday leave (£2m).

2.16.17 Regulatory assets arise when a US-based public utility, authorised by its regulator, defers to its balance sheet certain costs or revenues which will be recovered from or passed on to customers through future rate changes. Under IFRS, regulatory assets are not permitted to be recognised in the balance sheet. Instead, costs are charged to the income statement when incurred and recoveries from customers are recognised when receivable. This adjustment purely relates to the US business and therefore does not affect ECOC in the UK transmission business.

2.16.18 The provision for untaken holiday leave is a non-cash adjustment and as such does not affect ECOC.

Purchases of electricity

2.16.19 Under IFRS, the purchase cost of electricity increases by £182m for the NG group. The reason for this is a difference in the accounting treatment of regulatory assets in the US. See Payroll Costs section above.

2.16.20 Purchases of gas, rates, property taxes and electricity transmission services scheme direct costs.

2.16.21 These costs are not impacted by the adoption of IFRS.

Replacement Expenditure

2.16.22 Under UK GAAP repex was recognised as a cost when incurred. Under IFRS it is capitalised and depreciated over its useful economic life.

Other Operating Charges

2.16.23 The £331m decrease in other operating charges relate to several items as shown in Table 2-30 below.

Table 2-30: Reconciliation of decrease in other operating charges

Adjustment Movement

£m

Capital contributions relating to repex (17.0)

Non-recognition of regulatory assets in the US (296.0)

Pensions cost (22.0)

Non-recognition of intangibles 7.0

Other adjustments (3.0)

Total (331.0)

Source: Answer to DL1122



2.16.24 Capital contributions were previously recognised in the same period as the related

repex, under IFRS they are deferred in the balance sheet and credited to the income statement in line with depreciation. This adjustment does not affect ECOC.

2.16.25 Similarly to payroll and electricity purchases, the regulatory asset adjustment relates to the US business and therefore does not affect ECOC for the UK transmission business.

2.16.26 Under UK GAAP, the NG’s pensions and other post-retirement benefits were accounted for under SSAP 24. Under IFRS, these benefits are accounted for under IAS 19. The adjustment is required adjust the annual pension expense recorded under SSAP 24 to the IAS 19 measurement basis. This adjustment is purely an accounting entry and does not affect ECOC.

2.16.27 Development costs incurred in respect of the establishment of the NETA and BETTA systems were previously capitalised under UK GAAP. Under IFRS, these assets do not meet the definition of intangible assets and as such have been written off. This adjustment reflects the write off of these costs. As this cost is non-recurring no adjustment should be made to ECOC.

Conclusion

2.16.28 It is concluded that the conversion to IFRS will not have a material effect on ECOC.

2.17 Related party transactions

2.17.1 Within the total operating costs included in the HBPQ are costs which have been charged by other NG Group companies or other NG business units for services rendered. The risk in relation to these costs is that they may not represent the cost that would be achieved using an independent third party to provide the same services. If it were the case that the prices charged by another NG Group company or business unit to the transmission businesses was higher than an arms length price then the costs in the HBPQ would be artificially inflated.

2.17.2 This sub-section sets out the related parties from which NG have informed us the transmission businesses have incurred costs during the year. The costs associated with and the margins earned by those related parties on services provided to NG are discussed.

2.17.3 As part of previous price control reviews, margins earned by companies with less than 75% third party business have been removed for the purposes of the price control. Accordingly these margins have been removed from ECOC. As the HBPQ does not split the costs between forms of control but rather electricity and gas transmission, assumptions have been made to allocate the costs to specific forms of control.

2.17.4 As part of the HBPQ NG were asked to provide details of any charges of over £500,000 to the UK transmission businesses from other NG Group companies. Table 2-31 provides a summary of those charges included in the HBPQ.



Table 2-31: Related party costs in 2004/0537

Electricity

£m Gas £m

Total £m

Corporate Centre 7.8 4.2 12.0

Property Services Group 5.5 1.5 7.0

Network Mapping 1.5 0.1 1.6

Advantica 0.3 4.0 4.3

NGC Leasing 2.3 0.0 2.3

National Grid Insurance Company (Isle of Man) Ltd 9.2 5.9 15.1

National Grid Insurance Company (Ireland) Ltd 0.6 0.4 1.0

Total 27.2 16.1 43.3

Source: HBPQ

2.17.5 NG was also asked to provide analysis of the margins earned by the Group companies

on their transactions with the transmission businesses. It should be noted that these margins are not likely to be accurate. This is because the Group companies have no way of accurately allocating costs to different sales. The reason for this being that they have no need for this information.

2.17.6 The Corporate Centre costs are a recharge of corporate costs from National Grid Commercial Holdings Ltd. The costs are recharged with no margin added37. Therefore no adjustment to ECOC is proposed in respect of the corporate centre costs.

2.17.7 The Property Services Group is a collection of NG group companies as follows:

• National Grid Property Limited;

• National Grid Property Holdings Limited;

• Port Greenwich Limited;

• National Grid Investments Limited;

• Assethall Limited;

• Mainstream Forty Seven Limited;

• National Grid Land and Properties Limited;

• National Grid Property Developments Limited; and

• National Grid Property (Northampton) Limited.

2.17.8 The Property Services costs are going to be reviewed in detail by Property Consultants and therefore fall outside of the scope of this report. However it is noted that 77%37 of turnover of the Property Services Group is external to NG and therefore the margins should not be removed from ECOC.

2.17.9 Network Mapping provides a range of specialist products to worldwide power utilities. NG have stated that the service provided by Network Mapping are available in the market and the charges from Network Mapping compare favourably to those in the market place38. It is noted that only 30%37 of the turnover of Network Mapping is external to NG and on this basis the margin of £0.5m should be removed from ECOC.

37 Source: HBPQ tab 6.4




The entire internal margin arises in the electricity transmission business and it is assumed 100% of this arises within ETO.

2.17.10 Advantica provides technical support for gas specific activities such as forensic investigations and technical standard setting and review. They also provide technical training services.

2.17.11 Per the related party analysis provided by NG in the HBPQ the margin earned by Advantica on services provided to the transmission business is 3% for NGG and zero for NGET. The 3% margin for NGET indicates that of the £4m charges from Advantica to NGG £0.1m relate to a mark-up. This margin has been assumed to wholly relate to GTO and has been removed from ECOC as only 53%37 of Advantica’s business is external to NG.

2.17.12 NGC Leasing provide company cars for NGET staff.

2.17.13 A margin of 9% is earned by NGC Leasing on its charges to NGET. Since the total charges from NGC Leasing to NGET are only £2.3m this equates to a mark-up of £0.2m. This margin has been assumed to wholly relate to ETO and has been removed from ECOC as none37 of NGC Leasing’s business is external to NG.

2.17.14 Insurance costs are being reviewed in detail by Marsh and therefore fall outside of the scope of this report. However, it is noted that £5.5m and £2.9m margins are earned from the electricity and gas transmission business respectively. As none37 of the insurance companies’ business is external to NG, these margins have been removed from ECOC.

2.17.15 NG have stated39 the only way to allocate the margins is to split them in proportion to the insurance cost allocated to each form of control (which includes transactions and costs that are not sourced through captives).

2.17.16 This has resulted in the following reductions in ECOC by form of control.

Table 2-32: Costs to be removed from ECOC

ETO

£m

ESO

£m

GTO

£m

GSO

£m

Insurance margins 4.6 0.9 2.8 0.1

Total 4.6 0.9 2.8 0.1

Source: Answer to DL1130

Shared services

2.17.17 NG have stated that allocations of shared services costs to the Transmission businesses are done at cost40. Since no margin is added to the costs, no issue with respect to arms length trading arises.





Conclusion

2.17.18 Table 2-33 summarises the proposed adjustments arising from our analysis in respect of related parties.

Table 2-33: Proposed ECOC adjustments in respect of related parties

ETO £m

ESO £m

GTO £m

GSO £m

Costs to be removed from ECOC

Network Mapping 0.5 - - -

Advantica - - 0.1 -

NGC Leasing 0.2 - - -

Insurance costs 4.6 0.9 2.8 0.1

Total 5.3 0.9 2.9 0.1


2.18 Historic ECOC Analysis

2.18.1 The analysis contained in this section thus far has concentrated solely on the base year, 2004/05.

2.18.2 The following graphs compare ECOC in the base year, taking into account the adjustments proposed in our analysis, to ECOC in the historic years taking into account similar adjustments.

2.18.3 The starting point for these graphs is the ECOC balances provided by NG in their responses to questions DL1004 and DL1094.

2.18.4 The exceptional items adjustments were calculated by adding the exceptional items added into ECOC by NG41 to any cash costs added into ECOC by NG associated with the merger and restructuring42.

2.18.5 Non-operational capex has been excluded from ECOC in this analysis since as discussed in paragraph 2.15.34 above these costs should be considered separated to operating costs for the purposes of the price control review.

2.18.6 Excluded service costs have also been removed for ECOC in this analysis to retain consistency to their treatment in the base year.

2.18.7 It is noted that £31.9m of atypicals and non-cash costs were identified in the base year 2004/05. As such it is likely to there are atypicals and non-cash costs included in the historic years, however this report concentrates on the base year and these amounts for other years have not been quantified. Therefore no adjustment to ECOC has been made in respect of atypicals and non-cash costs for years other than the base year.

2.18.8 The ESO analysis exclude balances service charges since these large costs distort the graph.

2.18.9 Similarly the GSO analysis excludes shrinkage and storage costs since these large costs distort the graph.

41 Source: ECOC reconciliation provided in the responses to questions DL1004 and DL1094

42 Source: Response to questions DL1040 and DL1041



Figure 2-9: ETO Historic ECOC Performance43

0

50

100

150

200

250

2001/02 2002/03 2003/04 2004/05

£m

ECOC including adjustments Non-operational capex Exceptional items

Excluded services Atypicals and non-cash costs


Figure 2-10: ESO Historic ECOC Performance43

0

10

20

30

40

50

60

2001/02 2002/03 2003/04 2004/05

£m

ECOC including adjustments Exceptionals Non-cash costs


43 Source: HBPQ tables and response to question DL1004



Figure 2-11: GTO Historic ECOC Performance44

0

10

20

30

40

50

60

70

80

2002/03 2003/04 2004/05

£m

ECOC including adjustments Exceptionals Non-cash costs


Table 2-34: GSO Historic ECOC Performance44

0

5

10

15

20

25

30

35

40

45

2002/03 2003/04 2004/05

£m

ECOC including adjustments Exceptional items Atypicals and non-cash costs


44 Source: HBPQ tables and response to question DL1004



2.19 Conclusion

2.19.1 Table 2-35 sets out a summary of the proposed adjustments arising from the analysis above. The column headed Paragraph indicates in which paragraph of the report the analysis regarding that adjustment was performed.

Table 2-35 Summary of proposed adjustments to base year ECOC

ETO ESO GTO GSO Total

£m £m £m £m £m Paragraph

ECOC (per NG) 190.5 349.4 67.3 105.8 713.0

Adjustments proposed by Deloitte to amend ECOC

Exclusion of non-controllable costs:

Excluded services costs (1.1) - - - (1.1) 2.12.6

Employee share option costs (3.3) (0.7) (0.6) (0.5) (5.1) 2.12.9

Cash versus non-cash items:

Remove exceptional restructuring cash costs (1.6) - (2.2) (3.1) (6.9)

2.13.9, 2.13.17

Remove environmental clean up costs (0.5) - - - (0.5) 2.13.12

Remove onerous lease costs (1.4) - - - (1.4) 2.13.13

Add back carbon emission costs - - - 4.3 4.3 2.13.18

Atypical and non-recurring items:

Network Sales costs - - (0.7) (0.1) (0.8) 2.14.2-2

Severance costs (0.1) (0.1) 2.14.5

Investment for efficiency costs (3.0) - - (0.5) (3.5) 2.14.7-9

PLUGS (12.1) - - - (12.1) 2.14.10

Littlebrook subsidence repairs (0.6) - - - (0.6) 2.14.12

Atypical materials costs (5.0) - - - (5.0) 2.14.13

Control centre rationalisation costs - - - (2.4) (2.4) 2.14.16

Capitalisation policy:

No adjustments proposed - - - - -

Adoption of IFRS:

No adjustments proposed - - - - -

Related party transaction:

Network Mapping (0.5) - - - (0.5) 2.17.9

Advantica - - (0.1) - (0.1) 2.17.10

NGC Leasing (0.2) - - - (0.2) 2.17.13

Insurance costs (4.6) (0.9) (2.8) (0.1) (8.2) 2.17.14

Total adjustments (34.0) (1.6) (6.4) (2.4) (44.4)

ECOC including possible adjustments 156.5 347.8 60.9 103.4 668.6

Items included in ECOC that should be considered separately to operating costs for the purposes of the price control review

Balancing services charge - (303.1) - - (303.1) 2.12.4

Shrinkage - - - (58.4) (58.4) 2.12.5

Storage costs - - - (17.5) (17.5) 2.12.5

Non-operational capex (4.5) (2.0) (0.8) (0.8) (8.1) 2.15.34

Total (4.5) (305.1)

(0.8)

(76.7) (387.1)




3 Workstream B: Business Support Services

3.1 Introduction

Workstream objectives – benchmarking individual support services

3.1.1 The objective of Workstream B is to provide benchmarking information to enable Ofgem to make an assessment of whether certain business support service costs are at the appropriate level by comparing them with external benchmarks. For some areas we have also undertaken a brief qualitative review.

3.2 Approach

3.2.1 In order to deliver Workstream B, we adopted the approach illustrated in Figure 3-1.

Figure 3-1: Approach used in benchmarking support services

Review of HBPQ for trends and anomalies

Meetings Questions

Qualitativeview

Internal reference point/trends

Conclusions and reporting

Collection and normalisation of

data

Identification of benchmarking

data

Review of HBPQ for trends and anomalies

Meetings Questions

Qualitativeview

Internal reference point/trends

Conclusions and reporting

Collection and normalisation of

data

Identification of benchmarking

data

Review of HBPQ responses

3.2.2 We reviewed the HBPQ data submitted by National Grid, focusing mainly on changes in operating costs relating to business services. This included:

• evaluating trends in controllable operating costs over the four year period covered by the HBPQ;

• identifying any trend breaks or large variations in costs year-on-year;

• analysing the proportion of business services costs allocated to the Transmission business and how that has changed over time; and

• reviewing the narrative submitted as part of the HBPQ.

Prepare questions on business services

3.2.3 The review of operating costs for business services gave rise to around 90 questions which were submitted to National Grid. The purpose of this was to complete our understanding of the data and narrative submitted in the HBPQ. This was achieved by



seeking explanations for inconsistencies within the data and obtaining further information from National Grid to allow better understanding of the key issues and changes over the HBPQ period.

Meetings with the company

3.2.4 We have followed up our questions on business services with meetings with National Grid so that we can challenge and fully understand the data provided to us in the HBPQ. This included a number of meetings as set out below:

• Business services workshop: this focused in particular on HR, Finance and Procurement functions. It included a brief discussion of how the merger between NGC and Transco affected these functions.

• Merger savings workshop: National Grid presented their analysis on quantifying merger savings for the support functions with respect to the data submitted in the HBPQ.

• Operational Telecoms workshop: this was used to obtain an overview of the contractual framework in this area and to better understand the main cost drivers. A conference call was also held with National Grid to discuss certain aspects of the electricity transmission Operational Telecoms contract with Cable & Wireless.

• Corporate Centre workshop: this supplemented the business services workshop by analysing in greater detail the costs and activities included in the Corporate Centre.

• Allocations workshop: this meeting provided some further detail on how merger savings in business services could be allocated between the electricity and the gas business. It also provided an overview of the previous and current allocation methodology used by National Grid.

• Finance, Procurement and HR meetings: a series of conference calls were organised with National Grid and Deloitte subject matter experts to discuss qualitative issues in these functions.

Identification of benchmarking data

3.2.5 To conduct the benchmarking analysis we needed to identify potential benchmarking sources. This included assessing the availability and costs of benchmarks, and whether they were an appropriate comparator to use against National Grid.

Collection and normalisation of benchmarking data

3.2.6 Once the relevant sources were identified, the data was collected and normalised so that it could be compared with the information provided in the HBPQ.

Analysis of National Grid business services costs

3.2.7 The costs of business services were compared with the benchmarking data collected to support an assessment of the relative efficiency of National Grid. This has taken into account the impact of the merger on the business services and whether all the merger savings have been realised.

Drawing conclusions

3.2.8 Drawing together all the evidence collected from benchmarks, discussions with the company and responses to questions, we have formed our conclusions on the relative efficiency of National Grid’s business support services costs.



Reporting

3.2.9 This report contains a summary of our methodology, analysis and findings in relation to business services costs.

3.3 Scope

3.3.1 Table 3-1 below identifies the business services, as set out in the HBPQ, which are within the scope of the benchmarking analysis in Workstream B and those that are outside the scope. The business services included within scope account for 38% (£120m) of the £313m of total business services controllable costs reported by National Grid in 2004/05.

Table 3-1: Business services within and outside of scope

Within Scope Corporate Centre, Operational Telecoms, HR & Scheme Trainees, Business Services Finance, Procurement and Logistics, Legal, Safety Heath Environment and Security (SHES), Communications, Regulation and Internal Audit

Outside of Scope IS, Insurance and Property

3.3.2 In addition, we have also analysed the costs of the Transmission Finance business

unit. Although it is located within the Transmission business and only serves this area, it performs most activities associated with a Finance function. Our analysis will therefore include an assessment of Transmission Finance as well as the Business Services Finance function.

Review of cost allocation model

3.3.3 The review of the cost allocation model and its impact on business services costs allocated to the Transmission business have formed part of a separate workstream led by Ofgem and are not covered by this report.

Types of comparators surveyed

3.3.4 The types of comparators we have looked at in this workstream are at a high level. We recognise that these benchmarks are consistent only with forming an initial view on relative efficiencies. A list of the benchmarks used is included in Table 3-4 and includes among others:

• function FTE per total company FTEs;

• function costs per FTE;

• function costs as % of total company costs; and

• function costs as % of revenue.

Benchmarking reports provided by National Grid

3.3.5 As part of the price control review, NG has informed us of benchmarking reports it has commissioned in the last two years for its shared services. We note that we have received the following two reports from NG:

• Saratoga Benchmarking – Human Capital Metrics, Executive Scorecard for NGT UK – 2005; and

• The Hackett Group – Procurement Benchmarking Results, National Grid Executive Presentation.



3.4 Breakdown of Controllable Costs

3.4.1 The first step in our approach was to analyse the business services controllable costs for National Grid as set out in the HBPQ. This included analysing the proportion of the controllable costs for each business service that was allocated to the Transmission business.

3.4.2 Throughout this section, references to total business services costs exclude those services that are out of scope (i.e. IS, Insurance and Property) unless otherwise stated. Similarly, references made to allocation of costs to the Transmission business include both the TO and SO roles for the electricity and gas businesses.

3.4.3 As mentioned in the previous section covering Workstream A (Accounting Issues) we have reconciled the total costs in the HBPQ back to National Grid’s audited statutory accounts.

3.4.4 Figure 3-2 shows how the controllable costs of business services have changed over the last four years in real terms. The data for the first year (2001/02) refers to National Grid costs only prior to the merger with Transco. The HBPQ did not include data for Transco for 2001/02 so we have been unable to include this in any of our analysis.

Figure 3-2: Summary of business services controllable costs (2001/02-2004/05)45

Business services controllable costs

71%

44% 47% 50%

0

20

40

60

80

100

120

140

160

180

2001/02 2002/03 2003/04 2004/05

£ m

illion (2004/05 prices)

Total controllable costs Controllable costs allocated to Transmission Business

NGC only

Source: National Grid HBPQ data, in real terms (2004/05 prices)

3.4.5 Total controllable costs for the business services decreased by 25% in real terms

between 2002/03 and 2004/05 (20% in nominal terms). The business services costs apportioned to the Transmission businesses have decreased by 13% in real terms over the same period (9% in nominal terms). The proportion of controllable costs allocated to the Transmission businesses increasing from 44% in 2002/03 to 50% in 2004/05.

3.4.6 Had this proportion remained unchanged at 44%, business service controllable costs allocated to Transmission would be just under £53m for 2004/05, some £7.2m lower than in the HBPQ submission. We have discussed this issue with National Grid and they have pointed to the following three business services where the percentage decrease in costs of each function allocated to the Transmission business were lower than for the overall costs of the function.

45 Excludes IS, Property and Insurance costs



• Corporate Centre: costs have been allocated to the transmission business by applying the methodology previously used by NGC to the merged entity, which has been approved by the Securities and Exchange Commission (SEC). It uses direct attribution (where possible) as well as other key drivers – turnover, operating profit, employees and net asset value. National Grid was not able to inform us of the proportion of costs that are allocated directly and those that are allocated on key metrics. According to National Grid’s estimates, this accounts for around £3.3 m of the £7m difference we identified above. We discuss this issue further in our analysis of the Corporate Centre costs.

• Procurement and Logistics: the Didcot stores were transferred from Engineering Services to Procurement and Logistics, with 2003/04 being the first full year where this change is reflected. According to National Grid’s estimates, this accounts for around £2.5m of the £7m difference we identified above. We note that in the HBPQ data submitted by National Grid, total controllable costs for Engineering Services decrease by £5.8m between 2002/03 and 2003/04. However, we did not see any specific reference to the transfer of the Didcot stores in the HBPQ narrative that accompanied the cost data. We discuss this issue further in our analysis of the Procurement and Logistics costs.

• Safety, Health, Environment and Security (SHES): this did not exist as a separate function prior to 2004/05, with the majority of the staff included in the operating units of the business. This accounts for the remainder of the difference. We have been unable to trace back the costs of this function to the operating units to reconcile the creation of this area with cost reductions elsewhere. The level of detail included in the HBPQ did not allow us to perform this exercise.

3.4.7 Table 4-1 in Section 4 showed a breakdown of the business services operating costs allocated to the Transmission business for 2004/05 of £158m. Figure 3-3 shows how the totals shown in Table 4-1 relate to the analysis presented in this section of the report. Non-controllable costs, together with controllable costs for IS, Property and Insurance, total £98m. The remaining £60m are the controllable costs allocated to Transmission that fall within scope of the benchmarking exercise (i.e. 50% of £120m referenced in paragraph 3.3.1).

Figure 3-3: Business services controllable costs allocated to Transmission

Business Services costs allocated to Transmission (2004/05)

607

18

38

35158

0

20

40

60

80

100

120

140

160

Business

Services

allocated to

Transmission

Non-

controllable

costs

IS (controllable

costs)

Property

(controllable

costs)

Insurance

(controllable

costs)

Controllable

costs

£ m

illion

Source: National Grid HBPQ data



Controllable costs by business service

3.4.8 Table 3-2 shows a breakdown of the controllable operating costs in 2004/05 for the business services covered by our benchmarking analysis. It also shows the proportion of these costs that is allocated to the Transmission business.

3.4.9 The areas with the most significant business services costs in 2004/05 are Corporate Centre, HR (including scheme trainees) and Operational Telecoms. Business Services Finance, Procurement and SHES also account for over £10m in controllable costs.

3.4.10 A similar ranking can be seen with the business services costs allocated to the Transmission business. The main differences relate to Operational Telecoms (100% allocated to the gas and electricity Transmission business) and SHES (only 16% is allocated to the Transmission business).

Table 3-2: Controllable operating costs split by business service (2004/05)

Business Services (2004/05 data)

Total Controllable Operating costs for Business Services

Controllable Op. costs allocated to Transmission

(Electricity and Gas) %

Operational Telecoms 17.2 17.2 100

Corporate Centre 34.3 12.3 36

HR & Scheme Trainees 21.0 9.7 46

Procurement & Logistics 11.5 7.3 63

Business Services Finance* 10.2 3.2 31

Communications 5.3 2.9 55

Legal 5.8 2.6 45

SHES 11.4 1.8 16

Regulation 2.0 1.6 80

Audit 1.6 0.7 44

Other - 0.8* -

Total 120.2 60.1 50

Source: National Grid HBPQ data; * Excludes Transmission Finance Note: * Business services costs that have been attributed to Transmission but not to a particular function

3.4.11 The significance of the Finance function becomes more apparent when we add the

Transmission Finance operating costs for 2004/05 to those allocated to the Transmission businesses from the Business Services Finance (£3.2m), the total Finance cost equal £7.3m. This is equivalent to the Procurement & Logistics costs allocated to the Transmission business for 2004/05.

3.4.12 Following guidance from Ofgem, we have focused greater effort in our analysis on the following five areas (Corporate Centre, Operational Telecoms, HR, Procurement and Finance).

Business Services costs across the businesses

3.4.13 Figure 3-4 illustrates the split of controllable operating costs between the different gas and electricity transmission businesses. The graph shows that the majority of the costs are allocated to the electricity transmission business.

3.4.14 According to National Grid: “Most NGET business services costs are recorded in units that are “mapped” to ETO. An allocation is then made from ETO to ESO in Central adjustments on the internal sales / purchases accounting line.”46

46 Allocations workshop presented by National Grid, 21 February 2006, slide 8



3.4.15 We have therefore used this as a guide to identify the split of business services costs between the electricity TO and SO National Grid’s HBPQ submission.

Figure 3-4: Business Services Controllable operating costs allocated to each Transmission business (2004/05 prices)47

Opex Controllable Costs for Business Services

0

10

20

30

40

50

60

70

80

2001/02 2002/03 2003/04 2004/05

£(m

illions)

Gas SO

Gas TO

Electricity SO

Electricity TO

Source: National Grid HBPQ data and Deloitte analysis

Review of allocation methodology

3.4.16 Ofgem is conducting a review of the cost allocation methodology used by National Grid, supported by Deloitte in an advisory role. We have been asked to comment on Ofgem’s own review of the allocation methodology, and provide a report commenting on:

• the process and the work performed by Ofgem in assessing the allocation spreadsheet model; and

• the work performed by Ofgem in evaluating the new methodology.

3.4.17 We understand that Ofgem has not raised any significant objections to the proposed cost allocation methodology to be used by National Grid in the future. We provided advisory support to this workstream and our initial findings were set out in a draft report entitled “Comments on Ofgem's review of NGT's cost allocation methodology”.

3.5 Benchmarks Identified

3.5.1 We have identified four main sources for our benchmarking analysis of National Grid’s business services. These are identified below.

• External reports: a number of organisations specialise in collecting and analysing company data to produce published reports on benchmarks. These can be specific to a particular function, or may cover a number of business support services.

• Reports commissioned by National Grid: as part of ongoing process improvement and development of its business, National Grid has itself commissioned studies to analyse and benchmark a particular part of their business. Where these studies have been identified, we have requested a copy of the report from National Grid to be used in our own analysis.

• Electricity Distribution companies: data collected from the Regulatory Reporting Pack for the Electricity Distribution Companies has also provided some high level

47 Excludes IS, Property and Insurance costs



benchmarks for certain business service activities. We note that the cost categorisation of this dataset differs from that of National Grid, and a number of adjustments have been made to account for this in our analysis.

• Scottish Transmission companies: as part of the TPCR, Scottish Power and Scottish and Southern Energy have submitted cost data in relation to their Transmission businesses. Ofgem has also requested separate data for a number of support services as part of the benchmarking exercise. A complete set of data has not been received by Ofgem to date and we have therefore been unable to use it as part of our analysis. We understand Ofgem will undertake this analysis.

3.5.2 Trend analysis of historical data taken from the HBPQ submitted by National Grid has also been used as part of our analysis. In certain cases, we have also made references to the FBPQ submission, which provides a profile of estimated future operating costs for each function.

3.5.3 Previous price controls for both National Grid Company and Transco made use of benchmarking for assessing the efficiencies of business services. Table 3-3 shows some of the benchmarking ratios and sources used in the previous Transco Price Control Review48.

3.5.4 As Table 3-3 shows, a high proportion of the ratios used to benchmark Transco in the previous price control review were taken from information available for National Grid Company. These related mainly to Corporate Affairs costs and legal function costs. Clearly, this is no longer an option following the merger between the two companies in 2002.

Table 3-3: Benchmarks used in Transco’s last Price Control Review

Source Ratio

US Council of Public Relation Firms

Total FTEs per corporate affair FTE

FTEs per HR Dept FTE

HR Dept costs / total FTEs

EP-Saratoga Human Asset Effectiveness Report 2000/01

HR Dept remuneration / HR Dept FTEs

Legal costs as % of revenue Global Counsel 3000 Best Practice survey (Practical Law Company)

Annual cost per in-house lawyer

Corporate overheads per corporate FTEs

Corporate affairs costs per corporate affairs FTE

Corporate affairs costs as a percentage of total operating cost

Corporate communications spending as % of revenue

Total FTEs per legal FTE (FTEs)

Legal cost per legal FTE (£000s)

NGC

Legal costs as a percentage of total operating cost (%)

Source: “Report on Transco’s operating costs for the 2002/03 to 2006/07 Price Control Period” Arthur Andersen, Final Report 7 September 2001

3.5.5 Table 3-4 below list the different benchmarks by category for each of the business

support services covered in this report.

48 “Report on Transco’s operating costs for the 2002/03 to 2006/07 Price Control Period”, Arthur

Andersen, 7 September 2001



Table 3-4: Benchmarks used in current Transmission Price Control Review

Category Ratio Type of Source

Corporate Centre Total FTEs per corporate affair FTE Corporate affairs costs per corporate affairs FTE Corporate affairs costs as a percentage of total operating cost

Transco Price Control Review and Electricity Distribution Companies

HR FTEs per HR Dept FTE HR Dept costs per FTE HR Dept costs/Total costs

Saratoga HR benchmarking, Transco Price Control Review and Electricity Distribution Companies

Procurement Procurement costs as a percent of spend Procurement FTEs based on NG spend

The Hackett Group Procurement Benchmarking and Electricity Distribution Companies

Finance Total Finance functions costs as a percentage of revenues FTEs per billion US$ in revenue

The Hackett Group Finance function benchmarks

Communications Ratio of PR Budgets to Gross Revenues

Council of Public Relations Firms

Legal Total Legal spending as a percentage of revenues

2005 Hildebrandt US Law Department Survey

Safety, Health, Environment and Security

Total SHES costs as a percentage of total operating costs SHE costs per FTE

Electricity Distribution Companies

Regulation Total FTEs per Regulation FTE Regulation costs as a proportion of total operating costs

Transco Price Control Review

Audit Audit staff costs HAYS Salary Survey Data

3.5.6 We have sourced the following external reports for our benchmarking analysis:

• Saratoga (HR Benchmarking report);

• The Hackett Group, 2002 Book of numbers - Finance

• Council of Public Relations Firms, PR General Accepted Practices Study, (released in 2005);

• Summary of the 2005 Hildebrandt US Law Department Survey; and

• HAYS salary reports for Accounting & Finance.

3.5.7 The following documents were supplied by NG and were also used in our analysis of business services:

• Saratoga Benchmarking – Human Capital Metrics, Executive Scorecard for NGT UK – 2005; and

• The Hackett Group, Procurement Benchmark Results, Executive Presentation – 11 January 2006.

3.5.8 We identified other possible sources of information for benchmarking purposes, but these have not been used in our analysis. These are set out below.

• E&Y cost efficiency reports produced during the DPCR – We believe that the 2004/05 data collected through the Regulatory Reporting Pack is a better source for high level comparisons.



• BNA HR Department Benchmarks and Analysis 2005-06 – a broad study of HR function. Since National Grid commissioned a study from Saratoga, which was used in the Transco PCR, Ofgem concluded that it was not worth purchasing this report.

• Australian National Audit Office, "Benchmarking the Finance Function", 2002 – the data included for the Global sample was taken from the Andersen’s Global Benchmarking Database for 2001, which is now relatively old.

• KPMG, “Benchmarking the corporate function costs of NATS”, 2004 – a more recent study but it did not provide disaggregated data for comparison with National Grid.

3.6 Benchmarking Analysis

3.6.1 We now present the analysis conducted in assessing the relative efficiency of the business services within scope of this report.

• Operational Telecoms;

• Corporate Centre;

• HR & Scheme Trainees;

• Finance (Business Services Finance and Transmission Finance);

• Procurement and Logistics;

• Communications;

• Legal;

• Safety, Health, Environment and Security (SHES);

• Regulation; and

• Internal Audit.

3.6.2 For each business service we set out our findings in the structure shown below.

• An introduction giving a brief outline of the activities performed by the function as we understand from the HBPQ and meetings with NG. We have included summary data for each function which has been taken directly from the HBPQ and has not been audited or validated by us.

• An analysis of the historical trend of the cost over the HBPQ period and the main drivers for these changes, including any issues raised by observing trends in cost allocations to the Transmission businesses. The data shown has been taken from National Grid’s HBPQ submission and is shown in real terms (2004/05 prices).

• Our benchmarking analysis of the 2004/05 controllable costs including, where available, any reference to external studies.

• Our conclusions on our benchmarking analysis, including a view as to the range of potential efficiency adjustments emerging from our analysis.



3.7 Operational Telecoms

3.7.1 [excised at National Grid’s request]

3.7.2

3.7.3

Table 3-5: Source: National Grid HBPQ submission

Figure 3-5: Source: National Grid HBPQ submission



[excised at National Grid’s request]

3.7.4 49

49 National Grid response to Deloitte question DLB1082



[excised at National Grid’s request]

3.7.5

3.7.6

3.7.7 50

50 Response to Deloitte questions DLB1093, received 13 March 2006



3.8 Corporate Centre

3.8.1 Table 3-6 below summarises the key information and activities in relation to the Corporate Centre function as submitted by National Grid.

Table 3-6: Corporate Centre summary

Activities Metrics (taken from HBPQ) 2004/05

Staffing (FTEs) 118

Controllable Op. costs: £34.3m

Net staff costs £16.2m (47%)

Non-controllable Op. costs: £8.2m

Real change in controllable Op. costs: (2002/03-2004/05)

-£17.7m (-38%)

Audit NG Board Company Secretariat General Counsel and Risk & Compliance Group Corporate Affairs Corporate Responsibility Directorate Media Relations and Investor Relations Group Financial Control Taxation and Treasury Human Resources Group Strategy

% controllable costs allocated to Transmission in 2004/05:

36%

Source: National Grid HBPQ submission

3.8.2 The Corporate Centre provides a wide range of services to regulated and non-

regulated parts of the business, both in the UK and the US. National Grid did not include data on Transco’s Corporate Centre controllable costs in its HBPQ submission for 2001/02. During our discussions on merger savings, National Grid presented an estimate of £41.4m in nominal terms for these costs.

3.8.3 The sum of Transco and NGC Corporate Centre controllable costs for 2001/02 is estimated at £73.7m in nominal terms (£79.4m in 2004/05 prices). Therefore, Corporate Centre costs have reduced by £45m (57%) in real terms between 2001/02 and 2004/05 (Figure 3-6). This was driven mainly by the merger between NGC and Transco, with many duplicate corporate roles being eliminated and the establishment of a single Corporate Centre site.

3.8.4 In real terms, the Corporate Centre controllable costs for National Grid in 2004/05 (i.e. gas and electricity businesses together) are broadly the same as those of NGC (i.e. electricity alone) in 2001/02 before the merger with Transco.

Figure 3-6: Trend in Corporate Centre controllable costs

Total Controllable costs (2004/05 Prices)

-80

-70

-60

-50

-40

-30

-20

-10

0

2001/2 2002/3 2003/4 2004/5

£ (million)

Transco Corporate Centre costs

Other


Rents and buildings

Insurance

Non salary staff costs (including

T&S)


Net Staff Costs (including Agency

Costs)

Source: National Grid HBPQ submission; NG slides from Deloitte/Ofgem workshop, 3 February 2006



3.8.5 Figure 3-7 shows how Corporate Centre costs allocated to the transmission business have changed. Both electricity and gas is included from 2002/03 onwards. Overall costs are around £1m lower in real terms for 2004/05 compared to NGC pre-merger in 2001/02 (i.e. electricity only).

Figure 3-7: Trend in Corporate Centre costs allocated to Transmission

Costs allocated to Transmission (2004/05 Prices)

-16

-14

-12

-10

-8

-6

-4

-2

0

2001/2 2002/3 2003/4 2004/5

£ (million)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Controllablecosts allocatedto Transmission

% of totalcontrollablecosts allocatedto Transmission

NGC only


3.8.6 Corporate Centre costs allocated to Transmission businesses (gas and electricity) have

decreased by 15% in real terms between 2002/03 and 2004/05. This is lower than the 38% reduction for total costs of this function over the same period. As a result, the proportion of Corporate Centre costs allocated to Transmission has been rising since 2002/03. We note that the percentage for 2004/05 is just below the equivalent figure for 2001/02, which covers NGC only, before the merger with Transco.

3.8.7 NG has not provided details on why the decrease in total Corporate Centre costs is greater than the profile of costs allocated to the UK Transmission business. NG has stated that the 2004/05 figures use the same methodology for allocating Corporate Centre costs to its businesses as in previous years. The methodology has been approved by the SEC.

3.8.8 According to NG, the process for allocating Corporate Centre costs to Electricity Transmission has not changed between 2001/02 to 2004/0551. The process has three stages.

• Direct attribution of specific costs items: individually material costs that can be identified are wholly allocated to the relevant part of the business;

• Direct allocation based on time sheets: each group has a standard hourly rate calculate by dividing total department costs by total hours worked using a standard 37.5 hour week. In addition to business specific time codes, there is also a group code, which gets allocated based on metrics.

• Allocation based on metrics: costs that cannot be allocated directly and time recorded against a Group code are allocated using four metrics (turnover, operating profit, net assets and headcount).

51 National Grid, Allocations workshop, 21 February 2006



3.8.9 NG was unable to confirm the proportion of Corporate Centre costs that are allocated by each method. This is a key issue in assessing Corporate Centre costs reported in the HBPQ.

Availability of benchmarking data

3.8.10 Conducting benchmarking analysis for the Corporate Centre presents particular difficulties. Different organisations have different definitions of what they include in their corporate centre costs. Benchmarking companies do not specialise in corporate overheads since they are made up of often quite diverse components. Information from publicly traded companies is also of limited use since the level of detail is insufficient to provide a meaningful like-for-like comparison.

3.8.11 Given these issues, we have used a combination of different sources and data to assess the efficiency of Corporate Centre costs. We have undertaken:

• a brief review of the Corporate Centre costs by activity for 2004/05;

• used previous benchmarks for Corporate Affairs used in the Transco price review, adjusted where necessary for inflation and wage growth; and

• a comparison with DNO data collected through the Regulatory Reporting Pack, adjusted for comparability with National Grid.

Breakdown of Corporate Centre costs

3.8.12 As part of our analysis of Corporate Centre costs, we requested a breakdown of costs and FTEs by activity in this function for 2004/05. This information was given to us during a workshop with NG52 where we had the opportunity to discuss each of the activities within the Corporate Centre.

3.8.13 The breakdown we received is shown on Table 3-7. We note that the data includes £8.2m of non-controllable operating costs, which were categorised under “pension deficit/surplus” in the HBPQ. This gives a total operating cost of just over £42m for 2004/05 for the Corporate Centre.

Table 3-7: Corporate Centre 2004/05 costs and FTEs by activity Breakdown of Corporate Centre costs

by Activity

(2004/05)

Staff costsNon-staff

costsTotal

% of Total

Corporate

Centre

Costs

FTEs

Staff

costs /

FTEs

(£000s)

Audit 0.5 0.2 0.7 1.7% 2 250

Group Corporate Affairs 1 4.1 5.1 12.1% 12 83

Corporate Responsibility Directorate 1.1 0.6 1.7 4.0% 7 157

Group Financial Control 2.1 3.3 5.4 12.8% 13 162

General Counsel and Risk & Compliance 1 0.5 1.5 3.5% 9 111

Human Resources 1.4 2.6 4 9.5% 11 127

Investor Relations 0.6 0.5 1.1 2.6% 4 150

Media Relations 0.1 0.5 0.6 1.4% 2 50

Company Secretariat 1.1 3.6 4.7 11.1% 8 138

Group Strategy 0.6 0.3 0.9 2.1% 5 120

Taxation 1.1 0.6 1.7 4.0% 10 110

Treasury 2.9 2.6 5.5 13.0% 25 116

Other (NG Board and non-departmental) 6.8 2.6 9.4 22.2% 10 680

Total (incl. non-controllable costs) 20.3 22 42.3 100.0% 118 172 Source: National Grid Corporate Centre workshop, 21 February 2006

3.8.14 Certain activities at a Corporate Centre level yield benefits to the regulated business

through economies of scale. These are likely to include Treasury, Taxation, Internal

52 National Grid Corporate Centre – Ofgem/Deloitte workshop, 21 February 2006



Audit, Company Secretariat and possibly Investor Relations and Group Financial Control. If each of the regulated businesses had their own functions in these areas, we would expect the sum of these costs to be greater than the costs of the current structure. In these areas, the regulated businesses are likely to benefit from the centralised nature of these functions in a Corporate Centre.

3.8.15 The “Other” category represents over 22% of the Corporate Centre costs. According to NG, this includes “the board of directors … security costs… and costs associated with non-departmental costs, including some property costs”53 with travel and subsistence totalling £1m. We estimate that around half of the costs in the “Other” category relate to staff costs for the board of directors.

3.8.16 Group Strategy focuses on evaluating strategic options for the Group, which will mainly comprise issues not related to regulated business activities. Therefore, we would expect that the majority of these costs are not allocated to either Transmission or Distribution regulated businesses. As NG has been unable to split the costs between regulated and non-regulated businesses for each activity, we have not been able to determine whether Group Strategy costs are being allocated to the regulated businesses.

3.8.17 National Grid has stated53 that the Corporate HR function “establishes Group level HR strategy, policy and procedural framework”. We understand that these costs have not formed part of the HR benchmarking exercise undertaken by Saratoga for the shared services HR function. If this is the case, there is a question as to how much of these costs are allocated to the regulated businesses.

3.8.18 There are other activities where there may be some overlap of roles between the Corporate Centre functions and those of business services functions. In this case, it may be possible for issues relating to regulated businesses to be dealt with by the business services areas and not by Corporate Centre staff. We would expect Ofgem to address the issue as to which costs should or should not be included in the price control. Our analysis has focused on assessing the relative efficiency of the overall business support function.

Benchmarking against NGC in 2000/01

3.8.19 The previous Transco price control review included a comparison of “corporate affairs” costs between NGC and Transco for 2000/01. Corporate affairs was defined54 as including the following functions: corporate affairs (public relations and external communications), communications with customers and other stakeholders, government and European relations and environmental management. Group investor relations costs were also included.

3.8.20 We have constructed equivalent ratios for National Grid using 2004/05 data from the HBPQ. We have included the following Corporate Centre activities under the “corporate affairs” costs: Group Corporate Affairs, Corporate Responsibility Directorate, General Counsel and Risk Compliance, Investor Relations, Media Relations and Company Secretariat. This accounts for £14.7m and 42 FTEs of the total Corporate Centre costs (£42m and 118 FTEs).

3.8.21 We have also included costs and FTEs of the UK Communications function (£5.5m and 39 FTEs). Therefore the total “corporate affairs” costs for 2004/05 are estimated at £20.2m and 81 FTEs.

53 National Grid presentation, Corporate Centre costs, 21 February 2006

54 “Report on Transco’s operating costs for the 2002/03 to 2006/07 Price Control Period” Arthur

Andersen, Final Report 7 September 2001, page 48



3.8.22 Table 3-8 compares the previous “corporate affairs” ratios for NGC (i.e. electricity only) in 2000/01 with those calculated for National Grid in 2004/05 using data from the HBPQ. The 2000/01 ratios for NGC show a pre-adjusted value (i.e. the actual costs for NGC) and a post-adjusted value, which reflects the adjustments proposed by Ofgem’s consultants as part of the 1999/00 Price Control Review.

• FTEs per corporate affair FTE: the 2004/05 level of “corporate affairs” staffing is lower as a proportion to total employees relative to NGC’s 2000/01 benchmark. This result appears to indicate that the merger has been successful in reducing headcount in this area in relation to the total number of employees in the UK.

• Costs per corporate FTE: the benchmark obtained from NGC actual data for 2001/02 has been adjusted to account for inflation and growth in wages using gross average hourly earnings for all employees55. The costs reported in the Transco price control review have been increased by 14%, reflecting increases in costs over the period (50% of the increase is linked to wages and 50% is linked to inflation). Even taking this increase in the benchmark figures into account, corporate affairs costs per FTE appear to be almost 25% higher than the NGC 2000/01 post-adjustment benchmark.

• Corporate affairs costs as a percentage of total costs: the ratio calculated for 2004/05 for National Grid are below the previous NGC benchmarks, with function costs as a proportion of total operating costs equal to 0.66% compared to a benchmark of 0.97%.

Table 3-8: Comparing National Grid performance with previous TPCR benchmarks – corporate affairs

Benchmark Measure

NG

2004/05

NGC pre-adj post-adj

Total FTEs per corporate affair FTE 116 117 196

Corporate affairs costs per corporate affairs FTE, £000s 233 189 249

Corporate affairs costs as a percentage of total operating cost 1.06% 0.97% 0.66%

Range 2000/01

Source: “Report on Transco’s operating costs for the 2002/03 to 2006/07 Price Control Period” Arthur Andersen, Final Report 7 September 2001, Appendix 2

3.8.23 This analysis suggest that in terms of staffing levels, NG currently employs fewer staff

in “corporate affairs” as a proportion of total staff compared to NGC in 2000/01. We would expect this result given the headcount reductions that have taken place since the merger. However, this analysis does not give an indication as to whether the current level is efficient by today’s standards since we are using benchmarks from 2000/01. When “corporate affairs costs per FTE” are used as the benchmark, current costs appear to be around 7%-24% over the costs borne by NGC in 2000/01, after adjusting for wage and inflation growth.

Comparison with Electricity Distribution Companies

3.8.24 Our analysis has also included a high level benchmarking exercise between NG and the electricity distribution companies. We have taken two categories of indirect costs from the RRP (Legal & Company Secretary and CEO & Group Management) and compared it to NG’s Corporate Centre and Legal functions.

3.8.25 We have adjusted NG’s data to approximate the costs reported by electricity distribution companies. We have excluded Treasury, Taxation and Group Finance costs and FTEs for this comparison. This indicates that overall costs are in the top quartile (i.e. most efficient companies) compared to the distribution companies while staffing levels are in the second quartile, close to the median.

55 Source: Office of National Statistics



Table 3-9: Benchmarking National Grid with electricity distribution companies 2004/05 RRP data for DNOs National

Legal / Comp Sec / CEO & Grp Mgt min 25th 50th 75th max Grid

Department FTEs / Total FTEs 0.02% 0.44% 0.75% 1.35% 4.18% 0.73% 2nd quartile

Department costs as percentage of Total costs 0.15% 1.63% 1.99% 4.01% 7.79% 0.90% top quartile

Percentiles

Source: Ofgem (Regulatory Reporting Pack data) and Deloitte analysis

Summary of analysis on Corporate Centre

3.8.26 The benchmarking analysis undertaken for certain areas of the Corporate Centre has not shown any evidence of major inefficiencies. There have been significant cost reductions in this area following the merger between NGC and Transco. This was a key area for savings when the merger was announced and was under close scrutiny over the period 2002/03 to 2004/05 to make sure the announced savings were delivered. Therefore, it is plausible that there have been significant efficiency gains.

3.8.27 The benchmarking analysis of “corporate affairs” did highlight some potential efficiency adjustments. Taking the “corporate affairs costs per FTE” benchmark, current costs appear to be around 7%-24% over the costs borne by NGC in 2000/01. This adjustment is only made to the costs covered by corporate affairs related costs (i.e. Group Corporate Affairs, Corporate Responsibility Directorate, General Counsel and Risk Compliance, Investor Relations, Media Relations and Company Secretariat) which total £14.7m in 2004/05. This value includes a portion of non-controllable costs, which are estimated at £1m. We recognise that NG performs well against the Corporate Affairs costs as a percentage of total operating costs but the cost per FTE still suggests some scope for further efficiency savings, especially given the increase in scale of the business. Under this approach, the potential efficiency adjustment for “corporate affairs” controllable costs in 2004/05 equates to £0.9m to £3.3m.



3.9 HR & Scheme Trainees

3.9.1 Table 3-10 below summarises the key information and activities in relation to the HR and Scheme Trainees function as submitted by National Grid.

Table 3-10: HR and Scheme Trainees summary


Staffing (FTEs) 186 + 212 trainees





-£1.4m (-6%)

Business HR Strategies and plans; Strategy and Change management implementation; People Development/Succession Management; Resource management from sourcing to exit; Retention and Reward management; Organisational culture management and team development; Effective employee relations; Provision of effective decision support information; % controllable costs allocated

to Transmission in 2004/05: 46%


3.9.2 National Grid has pointed out that the HR business services function holds a number of

centralised costs for the business. Over half of the HR costs in 2004/05 relate to these non-core HR areas, the bulk of which relate to central training costs and the Scheme Trainees costs. Table 3-11 below gives a breakdown of these costs.

Table 3-11: Breakdown of HR costs by activity

Source: National Grid, presentation on business services, 26 January 2006

3.9.3 Costs reported in the HBPQ for HR and Scheme Trainees have decreased by around

6% in real terms between 2002/03 and 2004/05. However, NG has stated56 that “core” HR function costs have decreased by 33% since March 2002, from £14.1m in March 2002 to £9.5m in 2004/05, with FTE reductions from 270 to 186 over the same period.

56 Business Services workshop, 26 January 2006, slide 15



Figure 3-8: Trend in HR & Scheme Trainees controllable costs


-25

-20

-15

-10

-5

0

2001/2 2002/3 2003/4 2004/5

£ (million)

Other


Rents and buildings

Insurance

Non salary staf f costs

(including T&S)

Professional and consultancy

fees

Materials

Net Staf f Costs (including

Agency Costs)


Figure 3-9: Trend in HR & Scheme Trainees costs allocated to Transmission


-14

-12

-10

-8

-6

-4

-2

0

2001/2 2002/3 2003/4 2004/5

£ (million)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%Non-controllablecosts allocatedto Transmission




Benchmarking the HR function

3.9.4 In 2005, National Grid commissioned Saratoga to conduct a benchmarking exercise for its HR function. This included two elements: the Learning and Development function and the core HR function, excluding Payroll57. The analysis presented in this report has focused mainly on the core HR function.

3.9.5 Table 3-12 shows the results from the benchmarking study. The table shows how NG’s metrics for the core HR function fall within the top quartile in comparison to the selected sample group (i.e. above 75th percentile for FTEs per HR department FTE; below 25th percentile for HR department cost ratios).

57 Saratoga’s benchmarking database excludes payroll costs



3.9.6 Compared to the entire Saratoga database, which was also included in the results of the benchmarking report, NG falls short of top quartile performance in all three benchmarks, although its performance is well above the median.

3.9.7 We note that the HR benchmarking report supplied by NG did not include any data on top decile performance. This may have provided more evidence of NG’s performance within the top quartile relative to the selected sample.

Table 3-12: HR function benchmarks (excluding L&D and Payroll)

Saratoga HR benchmarking Percentiles NG

25th 50th 75th 2004/05

FTEs per HR Dept FTE 119

NG Selected Sample 66 79 108

Europe Database 71 94 135

HR Dept costs per FTE (£) 503

NG Selected Sample 820 1293 1694

Europe Database 406 729 1064

HR Dept costs/Total costs (%) 0.24

NG Selected Sample 0.30 0.50 0.66

Europe Database 0.22 0.36 0.65 Source: Saratoga, “Human Capital Metrics 2005 - Executive Scorecard for NGT”, June 2005, S1

Qualitative review

3.9.8 The main conclusion from the benchmarking study is that National Grid’s core HR performance is best practice relative to the peer group selected. This group, selected in conjunction with Saratoga, consists of the 15 companies shown in Table 3-13.

Table 3-13: Companies in NG selected sample for Saratoga benchmarking

Source: Saratoga, “Human Capital Metrics - Executive Scorecard for NGT”, June 2005, D1

3.9.9 In its documentation58, Saratoga states that “The validity of the comparison sample group is a critical aspect in benchmarking”. Saratoga assisted NG in deriving a list of suitable criteria for selecting the sample comparison group. This included considering industry sectors, company size and geographical coverage.

3.9.10 NG aimed for a wide sample of companies for benchmarking its HR function, including organisations in other regulated industries, privatised companies, as well as energy network companies. However, we note as shown below that utilities tend to have fewer HR FTEs per FTE than companies drawn from a wider range of sectors.

3.9.11 In previous price controls, a comparable benchmarking analysis was not performed. In 2001, Transco’s performance was benchmarked in relation to a “Utilities” and “UK”

58 HR Index™ Metrics, 2005 Documentation, p11



sample group. Therefore it may be more appropriate to compare NG’s performance to a wider sample of UK companies, or those in the same industry (i.e. Utilities).

3.9.12 Comparing NG’s performance with previous Saratoga benchmarks (Table 3-14) shows that NG’s ratios are again short of the top quartile performance for this function, although they are often at or above the median values. Staffing levels are about 10% short of the Utilities sample and almost 20% off the top quartile of the UK sample.

Table 3-14: Benchmark information from Saratoga report 2000/01 Saratoga Report 2000/01 Benchmark measures NGT

10th 25th Median 75th 90th Mean 2004/05

FTEs per HR Dept FTE 119

Utilities 112 113 117 134 157 130

UK 48 70 95 144 208 123

HR Dept costs / total FTEs (£000s) 503

Utilities 281 384 446 543 711 481

UK 221 369 594 1152 2282 960

Source: “Report on Transco’s operating costs for the 2002/03 to 2006/07 Price Control Period” Arthur Andersen, Final Report 7 September 2001, Appendix 2; HR Dept costs/total FTEs updated to 2004/05 prices.

3.9.13 We also note that the Corporate Centre includes an 11 FTEs dedicated to Group level HR Strategy. From discussions with NG, we understand that these costs (around £4m in 2004/05, including professional fees, training/employee survey) were excluded from the Saratoga benchmarking. This may partly explain the performance of NG relative to benchmarks. From our understanding of the Saratoga benchmarking, we believe that at least part of these costs (e.g. those that relate to HR strategy) should be included.

3.9.14 The benchmarking data presented here is a high level and does explicitly take into account the quality of the service provided by the HR shared service function. The performance on FTEs per HR department FTE ratio may indicate that they have a low number of HR staff but of high quality.


3.9.15 We have also conducted some high level benchmarking between NG and the electricity distribution companies, using data for HR and non-operational training. This analysis (Table 3-15) indicates that overall costs are lower than those for electricity distribution companies. We have not included non-operational training costs for NG as these costs are held by the operating units and cannot be separately identified in the HBPQ.

3.9.16 The Department FTEs over total FTEs ratio places NG in close to the median value relative to the electricity distribution companies. We have used the core HR function staff levels, which include Learning and Development staff. This may account for the NG’s performance on this benchmark.


HR & Non-operational Training min 25th 50th 75th max Grid


Department costs as percentage of Total costs 0.44% 0.71% 1.21% 2.43% 2.81% 0.32% below min

Percentiles


Summary of analysis on the HR & Scheme Trainees function

3.9.17 The performance of the HR function therefore depends on which sample is used as the benchmark. Taking the sample from the Saratoga benchmarking study conducted for NG, there is little evidence for potential adjustments in core HR function costs. However, using a different sample, there is a potential adjustment to staffing levels of up to 20%. This would be a significant adjustment to a function which performs above



average relative to any sample. Moreover, on the basis of benchmarking HR department costs, against total costs for a Europe-wide sample, a potential adjustment of up to 10% of staffing levels may be possible, equivalent to around £0.8m. We have also included a lower range estimate of zero reflecting the benchmarking against the NG Selected sample.

3.9.18 We note that this benchmarking analysis has focused mainly on core-HR function and it has not covered centrally held HR costs. Another key issue is how these centrally held costs are allocated to Transmission. This would require further information from NG, including a breakdown of core and non-core HR costs and how they are allocated to the Transmission businesses.



3.10 Finance (Business Services Finance and Transmission Finance)

3.10.1 Table 3-16 summarises the key information and activities in relation to the Business Services Finance function as submitted by National Grid. This is a shared service function that supports the whole of the UK business (i.e. transmission, distribution and non-regulated business).

Table 3-16: Business Services Finance summary

Activities – Business Services Finance Metrics (taken from HBPQ) 2004/05

Staffing (FTEs) 341





-£4.6m (-31%)

Key responsibilities are: Payments Claims Handling Banking System Support Management Accounting Credit & Risk Business Planning


32%


3.10.2 Table 3-17 summarises the key information and activities in relation to the

Transmission Finance function as submitted by National Grid. Transmission Finance is an operating unit within the Transmission business, which serves only the UK Transmission business. Therefore, its costs are allocated 100% to Transmission.

Table 3-17: Transmission Finance summary

Activities – Transmission Finance Metrics (taken from HBPQ) 2004/05

Staffing (FTEs) 75



Non-controllable Op. costs: £0m


-£0.47m (-10%)

Key responsibilities are: Statutory and regulatory reporting (for Transmission and NGC) Monthly reporting to management teams and Group finance Monthly management information to all Transmission operating units Planning and budgeting Investment appraisal and project accounting


100%


3.10.3 In Business Services Finance, there have been considerable reductions in controllable

cost between 2002/03 and 2004/05. Overall, costs have decreased by 31% driven by consolidation of the function together with the implementation of SAP. The Transmission Finance unit has also reduced costs by 10% over the same period and has increased its workload following the merger.



Figure 3-10: Trend in Business Services Finance controllable costs


-16

-14

-12

-10

-8

-6

-4

-2

0

2

2001/2 2002/3 2003/4 2004/5

£ (million)

Other


Rents and buildings

Insurance

Non salary staff costs

(including T&S)

Professional and

consultancy fees

Materials

Net Staff Costs (including

Agency Costs)


Figure 3-11: Trend in Transmission Finance controllable costs

Transmission Finance Controllable Costs (2004/05 prices)

-7

-6

-5

-4

-3

-2

-1

0

1

2001/2 2002/3 2003/4 2004/5

£ (million)

Other

Internal sales /

purchases

Non salary staff costs(including T&S)

Professional andconsultancy fees

Net Staff Costs

(including Agency

Costs)


3.10.4 The proportion of controllable costs in Business Services Finance allocated to the

Transmission business appears to increase in 2004/05. However, NG has clarified that this was not the case. According to NG, the HBPQ submission, included £1.6m of Business Services Finance costs allocated to the “other” category as part of the normalisation process. Adjusting the total for 2003/04 for this would give a higher total for this year, and hence the proportion allocated to Transmission would be higher in 2003/04 compared to 2004/05.



Figure 3-12: Trend in Business Services Finance costs allocated to Transmission


-4.5

-4.0

-3.5

-3.0

-2.5

-2.0

-1.5

-1.0

-0.5

0.0

2001/2 2002/3 2003/4 2004/5

£ (million)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

BSF costsincluded in 'Other'

Controllable costsallocated toTransmission

% of totalcontrollable costsallocated toTransmission

% adjusted


Benchmarking the Finance function

3.10.5 For our benchmarking analysis we have taken data from The Hackett Group 2002 Book of numbers for the Finance function. These benchmarks include data for the entire finance functions of various organisations. Therefore, in calculating comparable ratios for NG, we have added the FTEs and costs of Business Services Finance, Transmission Finance and Distribution Finance. The data for Distribution Finance costs for 2004/05 (73 FTEs and £5.9m in costs) was taken from the FBPQ submission59. This gives a combined Finance cost for 2004/05 of £21.1m and a total of 489 FTEs.

3.10.6 Table 3-18 shows the benchmark ratios used in our analysis. We have excluded outsourcing and technology costs from the ratios since IT costs for the finance functions have been included under the IS category in the HBPQ. The analysis shows that NG performs well against the average of the group but falls short of the world class benchmark ratios.

3.10.7 Total Finance function costs as a percentage of revenues are around 11% higher than the world class benchmark. The staffing levels ratio is over 30% above the world class ratio, although it is below the average level.

3.10.8 We also note that the benchmarks are for 2002 and we would expect improvements in both the average and world class benchmarks to have occurred between 2002 and 2005.

Table 3-18: Finance function benchmarks The Hackett Group, Finance Function

Benchmarking, 2002

NG

2004/05

Average World ClassTotal Finance function costs as a percentage of revenues (excl. Technology and Outsourcing) 0.82% 0.41% 0.46%

FTEs per billion US$ in revenue 103 44 65

2002

Source: The Hackett Group, Hackett Best Practices – 2002 Book of Numbers (Finance), page 14

59 L - Business Services Finance.pdf, Page 2 and 4



Qualitative Review

3.10.9 We have discussed the current and planned structure of the Finance functions with NG. We highlight the following issues that impact these functions.

• Organisational structure: following the merger, the Finance function is split into three areas already discussed, together with a Corporate Centre Finance function. Multiple and disparate structure for finance appears to be rooted on past experience rather than a clear business case.

• Finance processes: currently accounts payable (AP) and accounts receivable (AR) are provided for through the Business Services Finance shared services centre. Fixed Assets & General Accounting processes are run locally across the three areas. Conversely, the Corporate Centre provides a centralised service to all Finance areas in the form of Treasury, Tax and Investor Relations support.

• Technology: the existence of multiple ledgers on multiple systems e.g. SAP and Oracle is not an efficient configuration in terms of licensing fees, support costs, user training and upgrade management. In addition, multiple systems typically evolve multiple finance processes aligned to their specific operational environment e.g. IT systems.

• Regulatory compliance: NG’s core business operates within a regulated environment, including the need for detailed and historical data management and reporting. There is a misalignment between the statutory/management reporting and regulatory reporting to Ofgem by price control.

• Strategy: the current finance strategy and / or its implementation appear to be significantly lagging behind recognised and established finance function best practices. Of particular note is the delay and perhaps timing of the shared services centre implementation proposed by NG, where no convincing reasons for the time lag have been provided.

3.10.10 In its FBPQ submission, NG has highlighted the business services reorganisation plan (BSR) which will have a significant impact on the Finance function, including:

• centralising the majority of the Finance function into the Business Services Finance, with only a few dedicated staff in the Transmission Finance area;

• the proposed move to a single ERP platform across the entire Finance function is congruent to current best practices for finance and should contribute to additional efficiency & cost savings; and

• the proposed shared services reorganisation should reduce the FTEs required to complete manual tasks and manual decision making processes automated through the use of integrated technologies aligned to standardised processes.


3.10.11 We were unable to use data from electricity distribution companies for benchmarking NG. The source data in the Regulatory Reporting Pack has Finance (including tax, treasury, insurance premiums and insurance management) and Regulation costs as one category. We could have constructed a similar ratio for NG, but this would not be a suitable benchmark for the Finance function alone.

Summary of analysis on the Finance function

3.10.12 The high level benchmarking analysis conducted for the Finance function suggest that a potential adjustment to staffing levels could be made to the 2004/05 data. The FTEs per billion $US in revenue ratio for NG would have to decrease by 30% to reach the



world class value, while the finance function costs as a percentage of revenues suggests an efficiency gap of 11%.

3.10.13 Accordingly, our analysis suggests that a potential adjustment to Finance function staff costs of at least 11%would bring Finance function costs closer to a world class performance. We have also included a higher adjustment reflecting the findings of the qualitative review which has identified a number of efficiency initiatives. This equates to an adjustment of £0.9m to £1.7m for Business Services Finance function in 2004/05. A similar adjustment applied to the Transmission Finance would reduce costs by £0.42m to £0.76m using 2004/05 as the basis.

3.10.14 We note that the benchmark was conducted for the combined Business Services Finance, Transmission Finance and Distribution Finance costs and FTEs. We have implicitly assumed that an equal proportion of savings could be achieved in each of these areas.



3.11 Procurement and Logistics

3.11.1 Table 3-19 below summarises the key information and activities in relation to the Procurement and Logistics function as submitted by National Grid.

Table 3-19: Procurement & Logistics summary


Staffing (FTEs) 333





-£3.6m (-24%)

Procurement of goods and services Warehousing and transportation of materials High level procurement policy to ensure compliance with relevant European procurement legislation and relevant health & safety legislation Services provided to regulated and non-regulated businesses


64%


3.11.2 This function provides two key services for the business:

• Procurement - the procurement of goods and services in the support of day-to-day operations and the capital investment programme through the management of procurement contracts with suppliers; and

• Logistics - managing the warehousing and transportation of goods to final location, taking account of the stock management policies of the two different businesses (gas and electricity).

3.11.3 Since 2002/03, controllable costs for Procurement and Logistics have been reduced by almost 25%, driven by a restructuring initiatives as well as the elimination of duplicate roles following the merger between NGC and Transco. There has also been a reduction in workload associated with Distribution and non-regulated businesses.

Figure 3-13: Trend in Procurement and Logistics controllable costs


-18

-16

-14

-12

-10

-8

-6

-4

-2

0

2

4

2001/2 2002/3 2003/4 2004/5

£ (million)

Other


Rents and buildings

Insurance


(including T&S)


fees

Subcontractors

Net Materials


Agency Costs)

Source: National Grid HBPQ submission and Deloitte analysis

3.11.4 The proportion of controllable costs allocated to Transmission has actually increased

between 2002/03 and 2004/05. According to NG, the main reason for this was the transfer of the Didcot stores (a central store for high value, national strategic spares for



electricity) from Engineering Services to Procurement & Logistics function. The first full year reflecting this transfer is 2003/04 and accounts for around £3m of costs allocated to the Transmission business, according to NG60.

Figure 3-14: Trend in Procurement & Logistics costs allocated to Transmission


-8

-7

-6

-5

-4

-3

-2

-1

0

2001/2 2002/3 2003/4 2004/5

£ (million)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%


% of totalcontrollablecosts allocated

to Transmission


Benchmarking the Procurement function

3.11.5 National Grid commissioned a benchmarking study from The Hackett Group to assess the Procurement side of this function. We have received a copy of the presentation given to NG in mid January 2006. Our assessment of the costs for the Procurement function has been based on the analysis presented by The Hackett Group.

3.11.6 The main points arising from The Hackett Group presentation include:

• activities at a global level not formally/proactively pursued;

• staffing remains high in tactical activities despite the focus on strategic processes; and

• wage rates are 10% lower, helping to reduce cost despite the high number of FTEs.

3.11.7 Table 3-20 summarises the key benchmarks obtained from the analysis conducted by the Hackett Group. Procurement costs as a percentage of spend for NG are higher than the world class target and fall below the median benchmark. This suggests that there is scope for reductions in procurement costs of at least 8%.

3.11.8 The Procurement FTEs based on NG spend ratio also indicates that the staffing levels are higher than the median value and are a significant distance from world class performance.

Table 3-20: Procurement benchmarking results The Hackett Group: NG Executive Presentation

Benchmarking Results (11 January 2006) World NG

Median Class 2004/05

Procurement costs as a percent of spend 0.817% 0.739% 0.885%

Procurement FTEs based on NG spend 192 131 210 Source: The Hackett Group, National Grid Executive Presentation Benchmarking Results, 11 Jan 2006

60 National Grid TPCR workshop presentation to Ofgem / Deloitte, 3 February 2006




3.11.9 We have also conducted some high level benchmarking between NG and the electricity distribution companies. We have taken data from three indirect cost categories in the RRP (Vehicles & Transport, Stores and Procurement) as an approximation for NG’s Procurement and Logistics function.

3.11.10 Table 3-21 indicates that overall costs of this function as proportion of total costs are lower for NG compared to any distribution company. This could result from a number of reasons such as economies of scale, operating environment (especially on the Logistics side) or a mismatch between the categories defined in the RRP and what NG has reported in the HBPQ. The staffing ratio shows a different result, placing NG in the second quartile relative to the distribution companies.


Procurement / Stores / Vehicles & Transport min 25th 50th 75th max Grid


Department costs as percentage of Total costs 1.87% 2.14% 2.52% 3.09% 4.15% 0.82% below min

Percentiles


Qualitative Review

3.11.11 We have discussed the current and planned structure of the Procurement and Logistics function with NG. The following paragraphs summarise the main qualitative issues that we have identified from these discussions.

3.11.12 An overarching strategic plan has been developed to move the function from its current maturity to a higher level of performance incorporating category management, benefits tracking, improved processes and underlying systems to support. Whilst the key work streams and funding for the strategic plan have been defined at a high level, there is no implementation plan with expected benefits for each work stream.

3.11.13 The strategic plan should deliver significant procurement function efficiency and service and supplies procurement savings if implemented effectively over the next five years. The procurement function efficiency savings are expected to come from a number of areas.

• Transaction savings through improved systems and control mechanisms introduced by Ariba. This will include streamlined process for raising requisitions, electronic approval workflow, electronic transmission and receipt of purchase orders and invoices. The headcount savings are expected in the accounts payable team (which sits within Business Finance Services function), procurement team, and business owners (i.e. ordering goods and services).

• Up to date procurement information and data analytics from the “cchub” marketplace being introduced should enable the procurement team to effectively manage and control expenditure:

• the procurement team should be able to manage adherence to a rationalised supplier base and rationalised catalogue of goods; and

• demand and control management through a streamlined procurement system will provide pro-active cost avoidance savings.

• The category management organisation structure will see the introduction of a market facing team who, teamed with the right information, should be able to streamline the procurement process for categories and acquire better value for the business.

• An effective supplier relationship management approach coupled with category management should provide a platform for NG to differentiate their procurement



approach for categories from strategic to transactional. This will allow NG to match the most appropriate process to the category for an efficient procurement cycle:

• low value, high volume, transactional goods should be procured through electronic catalogues, requiring very little intervention from the procurement team; and

• higher value, lower volume, strategic services should be managed through structured relationships, driving out efficiency savings from the service received year on year.

3.11.14 NG will also require to “up-skill” staff in the Procurement function to meet the strategic plan. Therefore, although we expect future reductions in FTEs, the average cost per FTE is likely to increase as the skills profile increases. The current projections included in the FBPQ submission61 include a 12% reduction in FTEs after the planned Business Services Review and the sale of four gas distribution businesses. This excludes accounts payable FTEs which, as mentioned above, sit within the Business Services Finance function.

Summary of analysis on the Procurement & Logistics function

3.11.15 The benchmarking analysis conducted for this function shows that NG’s overall efficiency of the Procurement function falls short of median and world class measures as documented by the Hackett Group. There is the potential for reducing procurement staffing levels by over 30% if the world class benchmark is used, but this would not account for the fact that NG wage rates for this function (according to the Hackett Group) are already 10% lower than the benchmarks. Therefore, we propose an adjustment of between 8% and 16%, which is more in line with the overall procurement cost benchmark. This would lead to a reduction of £0.58m to £1.2m in the 2004/05 controllable costs for the Procurement and Logistics function.

61 National Grid FBPQ submission, “J - Procurement and Logistics.pdf”



3.12 Communications

3.12.1 Table 3-22 below summarises the key information and activities in relation to the Communications function as submitted by National Grid.

Table 3-22: Communications summary


Staffing (FTEs) 39





£3.0m (-36%)

Internal communications Press Crisis communications Issues management Regional communications Community relations Charitable donations Event management Intranet and internet site development Stakeholder management and corporate branding


54%


3.12.2 National Grid states that this function has a key role in “managing, protecting and

enhancing the reputation of the company across all of its UK stakeholder groups”. Certain activities are undertaken as part of the company’s licence condition (such as publicising the 0800 emergency gas service number - £0.7m in 2004/05), while others result from corporate policy (e.g. Environmental Educational Centres which help to meet NG’s commitment to operating as a socially and environmentally responsible business).

3.12.3 There have been significant reductions in controllable operating costs in this function between 2002/03 and 2004/05 (36% reduction in real terms). This has mainly resulted from the elimination of duplicate roles following the merger. As Figure 3-15 shows, costs in this function are still around 30% above the equivalent function costs of NGC before the merger in 2001/02.

Figure 3-15: Trend in Communications controllable costs


-9

-8

-7

-6

-5

-4

-3

-2

-1

0

1

2001/2 2002/3 2003/4 2004/5

£ (million)

Other

Prof it / loss on sale of fixed

assets

Rents and buildings

Insurance


(including T&S)


fees

Materials


Agency Costs)


3.12.4 Figure 3-16 shows the how the proportion of Communications costs allocated to the

Transmission businesses have changed over the last four years. We note that for



2004/05, the proportion allocated to Transmission (54%) actually increases compared to 2003/04.

3.12.5 We queried this issue with NG and their response has indicated that “2003/04 was a low year for Public Acceptance costs. Fewer County Shows used as part of our strategy to maintain and develop our relationship with wayleave grantors took place in that year. Costs returned to more normal levels in 2004/05”.62 The difference between the two years was £0.4m according to NG.

Figure 3-16: Trend in Communications costs allocated to Transmission


-5.0

-4.5

-4.0

-3.5

-3.0

-2.5

-2.0

-1.5

-1.0

-0.5

0.0

2001/2 2002/3 2003/4 2004/5

£ (million)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%Non-controllablecosts allocatedto Transmission




Benchmarking the Communications function

3.12.6 In benchmarking the Communications function we have taken information from the PR General Accepted Practices Study, published in 2005 by the Council of Public Relations Firms. We have used PR budgets as a proxy for this function. The study included the key responsibilities for the PR function which were broadly similar to those carried out by National Grid’s Communications function.

3.12.7 Table 3-23 below shows the ratio of Communications costs to gross revenues, split into two revenue categories. The benchmarks show that NG’s Communication budget is twice the average for the highest revenue category. We recognise that the nature of NG’s business places particular demands on its Communications function given contingency plans required for crisis management and the number of stakeholders it has to engage with as part of its business.

Table 3-23: Communications function benchmarks Council of Public Relations Firms,

PR General Accepted Practices Study

NG

2004/05

Revenue category US$3.1-US$6bn above US$6bn

PR budgets to Gross Revenues (%) 0.01% 0.06% 0.12%

2004

Source: Council of Public Relations Firms, PR General Accepted Practices Study, issued 2005

3.12.8 Nevertheless, the level of Communications spend is double the benchmark for

companies with revenues above US$6bn. Controllable costs allocated to the Transmission business in 2004/05 (£2.9m) also appear high for what is essentially a

62 National Grid response to Deloitte question DLB1044



regulated natural monopoly business. Table 3-24 gives a breakdown of initiatives and associated costs for this function in 2004/05.

Table 3-24: Initiatives and associated costs for National Grid Communications activities in 2004/05 Category of Spend £'m

0800 Emergency Gas Service 0.7

Educational Environmental Centres (EEC's) 0.5 Grantors County Show Programme 0.5 Networking magazine 0.2

Media Monitoring 0.1

Total 2.0 Source: National Grid, response to questions DLB1077

Summary of analysis on the Communications function

3.12.9 The benchmarking analysis indicates that there is a potential adjustment to the 2004/05 Communications costs of up to 50%. This would bring NG in line with the average benchmark for PR budgets as a proportion of gross revenues, in the revenue category above $US6bn. This could be applied to the entire function and to the costs allocated to Transmission while still maintaining certain initiatives that National Grid considers to be key for running its business. This adjustment implies that up to £2.7m in costs could be eliminated from the total costs of this function for 2004/05.

3.12.10 However we have included a lower bound adjustment of 7% reflecting the benchmarking of the corporate affairs function which included UK Communications costs. This range also reflects the discretionary nature of some of this expenditure.



3.13 Legal

3.13.1 Table 3-25 below summarises the key information and activities in relation to the Legal function as submitted by National Grid.

Table 3-25: Legal summary


Staffing (FTEs) 46





£-2.9m (-33%)

Provide legal advice to all areas of the business; Manage the provision of external legal advice; Provide information and guidance on changes in legislation that will affect the UK Business; Liaise with National Grid Group Legal, National Grid (US) Legal; Develop, manage and continually improve National Grid UK's approach to risk management, compliance and business continuity; Promote ethical behaviour;


44%


3.13.2 The main activity of this function is to provide legal services to the UK business.

Controllable costs for the Legal function have reduced by a third between 2002/03 and 2004/05 driven by restructuring of the organisation following the merger.

3.13.3 The costs of this function allocated to Transmission have decreased by almost 50% in the same period, as illustrated in Figure 3-18. Controllable costs for 2004/05 are just over £2.5m, which compares to almost £4m in 2001/02 (in real terms) for NGC pre-merger.

Figure 3-17: Trend in Legal controllable costs


-10

-9

-8

-7

-6

-5

-4

-3

-2

-1

0

2001/2 2002/3 2003/4 2004/5

£ (million)

Other


Rents and buildings

Insurance


(including T&S)


fees

Materials


Agency Costs)




Figure 3-18: Trend in allocation of Legal costs to Transmission


-5.0

-4.5

-4.0

-3.5

-3.0

-2.5

-2.0

-1.5

-1.0

-0.5

0.0

2001/2 2002/3 2003/4 2004/5

£ (million)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100% Non-controllablecosts allocated

to Transmission




Benchmarking the Legal function

3.13.4 Our benchmarking analysis uses two sources of information to compare NG’s performance. We have used a summary of a US Law department survey published by Hildebrandt to assess overall costs relative to turnover. Additionally, we have taken data from the General Council 3000 best practice survey used in Transco’s previous price control review.

3.13.5 A summary of the benchmarks calculated are shown in Table 3-26. The results from the Hildebrandt survey indicate that NG’s overall costs relative to revenues are quite low relative to the world wide sample median. We do not have data on the distribution of this ratio, so are unable to comment on whether NG is in the top quartile for this measure. We also note that the world wide sample used is inflated by US companies – the Hildebrandt survey shows that spend as proportion of revenue is higher in the US sample compared to the world wide sample.

3.13.6 We have also used a similar ratio used in Transco’s last price control to benchmark NG’s legal function. In this case, we get a similar result whereby the legal department costs as percentage of revenue are below the benchmark.

Table 3-26: Legal function benchmarks

2005 Hildebrandt US Law Department Survey, Summary 2004

NG

2004/05

0.13%

Revenue band

>US$6bn -

<US$10bn

Total Legal spending as %age of revenues (world wide sample) 0.41%

General Council 3000 Best Practice Survey 1999

Legal costs as a percentage of revenues (UK sample) 0.15% Source: 2005 Hildebrandt US Law Department Survey, Summary; General Council 3000 Best Practice Survey, 1999

Summary of analysis on the Legal function

3.13.7 The high level analysis conducted for the Legal function suggests that the overall function costs, as a proportion of revenues are below the benchmarks identified. Therefore, we do not have evidence to support any adjustment to the 2004/05 Legal function costs for NG.



3.14 Safety, Health, Environment and Security

3.14.1 Table 3-27 below summarises the key information and activities in relation to the Safety, Health, Environment and Security (SHES) function as submitted by National Grid.

Table 3-27: Safety, Health, Environment and Security summary


Staffing (FTEs) 109





n/a

To meet statutory, regulatory and policy obligations for safety, health environment and security Unit delivers safety, health and environment and security advice whilst operating units across the business have line management responsibility


16%


3.14.2 The SHES directorate structure and operating model was developed during 2004/05.

Previously, the activities undertaken by SHES had been dispersed throughout the operating units of the business. For this reason, we are unable to conduct trend analysis on the costs of this function for the period 2001/02 and 2004/05.

3.14.3 NG has provided an estimate of costs for 2003/04 of £16.5m, which implies a reduction of 30% in costs to 2004/05. The main driver for this has been a reduction in FTEs and a migration and alignment of staff from disperse groups into a central function. This is expected to deliver continued savings in 2005/06. We have not traced back FTE and associated cost reductions in other areas of the business arising from the creation of this separate function.

Figure 3-19: SHES controllable costs


-18

-16

-14

-12

-10

-8

-6

-4

-2

0

2001/2 2002/3 2003/4 2004/5

£ (million)

Other


Rents and buildings

Insurance

Non salary staff costs (including T&S)


Subcontractors

Materials

Net Staff Costs (including Agency

Costs)

Source: National Grid HBPQ submission and Business Services workshop slides, 26 January 2006


3.14.4 To benchmark the SHES function, we have used data from Ofgem supplied by the electricity distribution companies through the Regulatory Reporting Pack (RRP). We have compared this function to the costs of “Health, Safety and Operational Training”.



We have adjusted the cost data for NG to include the centrally held training costs included in the HR function (i.e. £4.7m) to account for Operational Training.

3.14.5 Table 3-28 summarises the results of our analysis of the SHES function. For 2004/05, NG consistently performs in the top quartile relative to the 14 electricity distribution companies. We would expect this to be the case as NG will be able to explore scale economies in this function when compared to the electricity distribution companies.

Table 3-28: SHES function benchmarking Data for Electricity Distribution Companies collected

through the Regulatory Reporting Pack (2004/05)

NG

2004/05

Staffing 25th 50th 75th

Department FTEs/Total FTEs (%) 0.93% 1.33% 1.66% 0.76%

Department Costs

H&S department costs as a percentage of total costs 0.85% 1.03% 1.49% 0.53%

H&S department costs as a percentage of revenue 0.42% 0.49% 0.73% 0.35%

Percentiles


Summary of analysis on the SHES function

3.14.6 The benchmarking analysis undertaken for this function using data from the electricity distribution companies gives no evidence of inefficiencies in NG’s SHES function. We note that this has been a high level exercise and has relied solely on the information provided through the RRP. On this limited evidence, we cannot propose any adjustments to the 2004/05 cost base for the SHES function.



3.15 Regulation

3.15.1 Table 3-29 below summarises the key information and activities in relation to the Regulation function as submitted by National Grid.

Table 3-29: Regulation summary


Staffing (FTEs) 19





£0.146m (8%)

Developing and negotiating incentive arrangements Development of regulatory policy in respect of National Grid's distribution activities. Development of Regulatory Strategy. Preparing for future price reviews Raising awareness of licence and key legislative obligations on both the gas and electricity side and providing interpretation and advice on regulatory issues.


78%


3.15.2 This function provides support in managing regulatory issues and legislative obligations

for the UK businesses. We have excluded the costs of the Transmission licenses from our analysis – these are considered non-controllable costs. In its HBPQ submission, NG has only included controllable costs for its core Regulation function, i.e. it has excluded costs and FTEs that are brought in during price control reviews. Costs in this core Regulation function have increased by 8% since 2002/03.

3.15.3 The current structure of the core Regulation function was developed following the merger and is based on a non-price review workload. Between 70% and 80% of controllable costs have been allocated to the Transmission business over the period 2002/03 and 2004/05.

3.15.4 From meetings and discussions with NG, we have estimated that for 2005/06 the TPCR team comprises of 15 FTEs and around £1.2m in addition to the core Regulation team. For 2006/07, costs for Regulation (core and TPCR) will reach a peak of around £3.8m.

Figure 3-20: Trend in core Regulation controllable costs


-2.5

-2.0

-1.5

-1.0

-0.5

0.0

0.5

2001/2 2002/3 2003/4 2004/5

£ (million)

Other


Insurance


(including T&S)


fees


Agency Costs)




Figure 3-21: Trend in core Regulation costs allocated to Transmission


-2.0

-1.8

-1.6

-1.4

-1.2

-1.0

-0.8

-0.6

-0.4

-0.2

0.0

2001/2 2002/3 2003/4 2004/5

£ (million)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Controllable costs

allocated toTransmission

% of total

controllable costsallocated toTransmission


Benchmarking the Regulation function

3.15.5 This function is similar to the Corporate Centre in that there are few readily available benchmarks. Therefore, we have taken NGC data for 2000/01 that was used in Transco’s previous price control. We have adjusted the cost benchmark to account for increases in wages since 2000/01, as the majority of the controllable costs of this function are staff costs. We have assumed an annual increase of 4.5%. The original figure for the “Regulation cost per regulation FTE” reported for NGC63 has therefore been increased by 19%.

3.15.6 Table 3-30 shows how NG in 2004/05 compares with benchmarks. In terms of staffing levels and costs as a proportion of total costs, 2004/05 ratios indicate better performance compared to NGC’s previous ratios in 2000/01. This is also the case when we benchmark the core regulation function together with the TPCR team for 2005/06.

3.15.7 Taking the regulation cost per regulation FTE benchmark, the current ratio for National Grid’s core regulation function is higher than the benchmark. However, if we take the core function and the TPCR team together, the result is in line with NGC’s performance in 2000/01, after adjusting for wage growth.

Table 3-30: Regulation function benchmarks NGC

2000/01

NG 2004/05

(Core)

NG 2005/06

(incl TPCR)

Total FTEs per regulation FTE (FTEs) 197 834 466

Regulation cost per regulation FTE (£000s) 94 106 94

Regulation costs as a percentage of total operating costs (%) 0.24% 0.07% 0.11% Source: “Report on Transco’s operating costs for the 2002/03 to 2006/07 Price Control Period” Arthur Andersen, Final Report 7 September 2001, Appendix 2; National Grid, Business Services workshop, 26 January 2006

Summary of our analysis on the Regulation function

3.15.8 Overall the costs associated with the Regulation function (core and TPCR team) appear to be reasonable in 2004/05 when compared to NGC’s position in 2000/01. The benchmarks indicate that savings have occurred through headcount reductions

63 “Report on Transco’s operating costs for the 2002/03 to 2006/07 Price Control Period”, Arthur

Andersen, 7 September 2001, Appendix 2, Table 2-8, page 13



following the merger. Overall costs as a proportion of total costs are also lower, reflecting changes in staffing levels. Given our benchmarking analysis of this function, we do not propose any adjustments to the overall 2004/05 core Regulation costs.



3.16 Internal Audit

3.16.1 Table 3-31 below summarises the key information and activities in relation to the Internal Audit function as submitted by National Grid.

Table 3-31: Internal Audit summary


Staffing (FTEs) 23





-£0.43m (-21%)

To provide an internal assurance role across the UK businesses; Primary objective is to provide the National Grid Board with an accurate and independent assessment of the key risks and control weaknesses facing the UK businesses;


41%


3.16.2 The Internal Audit function is the smallest of all the business services functions covered

in this report. The majority of the costs in 2004/05 (almost 90%) are staff costs. Controllable costs have decreased by 21% between 2002/03 and 2004/05. This resulted from forming a single audit function following the merger in 2002. Less than half of the costs of this function are allocated to the Transmission businesses.

Figure 3-22: Trend in Internal Audit controllable costs


-2.5

-2.0

-1.5

-1.0

-0.5

0.0

0.5

2001/2 2002/3 2003/4 2004/5

£ (million)

Other



(including T&S)


fees


Agency Costs)




Figure 3-23: Trend in Audit costs allocated to Transmission


-1.2

-1.0

-0.8

-0.6

-0.4

-0.2

0.0

2001/2 2002/3 2003/4 2004/5

£ (million)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100% Non-controllablecosts allocatedto Transmission




Benchmarking the Internal Audit function

3.16.3 In benchmarking this function we have focused on staff costs and used Hays Guide to Salaries in Accountancy & Finance issued in 2004. NG’s average net staff cost in 2004/05 for this function is just under £62,000. Assuming that benefits and bonuses account for 10% of staff costs, then the average salary for the Audit function is estimated to be around £55,500.

3.16.4 Table 3-32 shows ranges for base salaries for three different levels of internal audit staff based in London and the Midlands for companies with annual turnover above £100m. These figures are for base salary only (i.e. exclude benefits and bonuses). We do not have detailed information on the different grades of staff employed in this function, so we have compared the average cost of the function.

3.16.5 Using salary data for the Midlands region, average staff costs for this function appear to be at the top end of the scale. We note that we have used this region as a benchmark since the Internal Audit function is located in Warwick. We would expect a mix of different grades to exist – a few Senior Audit Managers supported by Internal Audit staff – which would lead to an average salary cost for the function under £55,500 per FTE.

Table 3-32: Audit function staff cost benchmarks HAYS, Guide to Salaries in

2004 (Internal Audit)

NG

2004/05

Region London Midlands

Senior Audit Manager 60,000-80,000 50,000-60,000

Audit Manager 50,000-70,000 45,000-50,000

Senior Internal Audit 45,000-55,000 40,000-45,000

Average net staff cost (£) 61,705

Salary range for companies

with turnover >£100m (£)

Source: HAYS, Guide to Salaries in Accountancy and Finance - 2004

Summary of our analysis on the Internal Audit function

3.16.6 Given our analysis of this function, it appears that staff costs are at the high end of the range when compared to the HAYS salary survey data for the Midlands region. On this basis, there is a potential for adjusting 2004/05 salary costs by up to 10% (£0.14m), as indicated by the benchmarking analysis.



3.16.7 We recognise that some allowance may be made for the complexity and size of the business which may require a higher calibre of internal auditors, which will in turn demand salaries at the higher end of the scale. We also note that this function is subject to increasing workloads in the future, including the support of external policy compliance through review and testing of key controls in relation to Sarbanes-Oxley.

3.17 Conclusions

3.17.1 The overall view from our benchmarking the business support services at a high level is that the costs for 2004/05 compare well with our benchmarks. These functions were key to deliver merger savings and it is not surprising that this has driven costs down to a level that compares well with most benchmarks.

3.17.2 The sum of potential cost adjustments for 2004/05 ranges from £2.8m to £9.9m (2.3% to 8.2%) in the business services areas covered by this section of the report (Table 3-33).

3.17.3 Potential adjustments at the lower end of the scale include efficiencies under “corporate affairs” (includes part of Corporate Centre costs and Communication costs), Procurement and Logistics and Business Services Finance. Other functions did not exhibit significant variations from average or median performance of our benchmarks.

3.17.4 We have also suggested a higher range of potential efficiency adjustments. This has taken a more optimistic position by comparing National Grid with top quartile or world class performance. Adjustments in this area covered higher savings for “corporate affairs”, Procurement and Logistics and Business Services Finance. It also includes adjustments for the core HR function, Internal Audit and Operational Telecoms.

3.17.5 We have not proposed any adjustments to Legal, SHES and Regulation given the results of the benchmarking analysis conducted in these areas.

Table 3-33: Summary of potential savings in business services (2004/05) (£ million)

Business Area

Total

Controllable

Operating

Costs

Potential

Adjustment

(%)

low high

Operational Telecoms 17.2 0.0 -0.1 17.2 17.1 0%-0.6%

Corporate Centre 34.3 -0.9 -3.3 33.4 31.0 3%-10%

HR & Scheme Trainees 21.0 0.0 -0.8 21.0 20.2 0%-4%

Procurement & Logistics 11.5 -0.6 -1.2 10.8 10.3 5%-10%

Business Services Finance 10.2 -0.9 -1.7 9.3 8.6 9%-17%

Communications 5.3 -0.4 -2.7 5.0 2.7 7%-50%

Legal 5.8 0.0 0.0 5.8 5.8 0%

SHES 11.4 0.0 0.0 11.4 11.4 0%

Regulation 2.0 0.0 0.0 2.0 2.0 0%

Audit 1.6 0.0 -0.1 1.6 1.5 0%-9%

Total 120.2 -2.8 -9.9 117.4 110.4 2.3%-8.2%

Transmission Finance 4.1 -0.42 -0.76 3.6 3.3 9%-17%

Total (incl Trans. Finance) 124.3 -3.2 -10.6 121.1 113.7 2.6%-8.6%

Deloitte

Estimates

2004/05

Potential

Savings

Source: Deloitte benchmarking analysis

3.17.6 We note that our analysis has been conducted for a particular year (2004/05) and for a particular organisational structure. We recognise that there may be potential for further efficiency savings to be made if particular functions are merged or reorganised.



4 Effect of the NGC/Transco merger

4.1 Introduction

4.1.1 This section summarises our findings in relation to the merger between NGC and Transco in 2002. We have referenced external reports from third parties, National Grid presentations and documents produced for NGC and Transco by their consultants. We also refer to presentations made by National Grid to Ofgem which focused on analysing merger savings using data from its HBPQ submission.

4.2 Original target for merger savings

4.2.1 At the time of the merger announcement in mid-2002, the initial expectations for savings were of at least £100m per annum by the end of the first full financial year of the merged company (i.e. 2003/04).

4.2.2 The financial benefits were expected to arise principally from the elimination of duplicate head office costs, other central cost savings and from the combination of support services functions provided to the UK regulated electricity and gas businesses. Additional savings were expected from the combination of certain activities of the two UK transmission businesses, from sharing of best practice and further financial synergies.

4.2.3 PwC conducted a review of the potential merger benefits on behalf of the NGC and Lattice Boards. The final report64 was published on the 14 June 2002. National Grid provided us with a copy during the course of our work. PwC’s analysis focused on operational synergies identified in the:

• UK Regulated businesses;

• Corporate Head office; and

• Telecoms businesses.

4.2.4 Ongoing annual savings were estimated at between £65-80m for Corporate Head office and UK regulated business, with £5m savings identified for Telecoms business. The report highlights that the lack of line management in the quantification process can mean that additional synergy opportunities may exist that have not been identified. Also, there were some areas that were not reviewed in detail by PwC (e.g. Property excluding distribution centres and depots) that could fill the gap between the merger savings announced (£100m) and PwC’s assessment.

4.3 External view of possible merger savings

4.3.1 Reports by brokers following the merger announcement appeared to support NG’s view of merger savings. Most analysts stated that the initial merger savings target of £100m p.a. could easily be exceeded. Estimates for merger savings ranged from £125m to £225m p.a.

4.3.2 Morgan Stanley65 stated that the combined company should be able to achieve merger savings equivalent to some 15% of its UK controllable cost base. Their estimate was of up to £225m p.a. of merger savings.

4.3.3 Smith Barney Citigroup report66 had a more conservative view. They assumed that NG’s merger savings target could be exceeded by 50%, achieving a £150m annualised

64 PwC, Project Leopard, Merger Benefits Final Report, 14 June 2002

65 Morgan Stanley report on NGT, 22 October 2002

66 Smith Barney Citigroup (Europe/UK Research) report on NGT, 10 January 2003



cost savings. This was similar to an estimate from Credit Suisse First Boston67 suggesting merger savings reach £135m by 2006.

4.3.4 A UBS report68 estimated cost reductions to be £100m in 2003/04 (in line with the stated target by NG) but increasing to £125m in 2004/05. The further £25m arises, according to the report, from operational integration (which had not been included in the company’s target).

4.3.5 In general, analysts believed savings would mostly be achieved through the elimination of duplicate head office and other central costs. In particular, there was significant overlap in support functions at the corporate level, such as human resources, finance and payroll. Scope for rationalisation could also be found in sharing IT systems and processes; increased purchasing power and from the sharing of best practices in running the UK businesses.

4.4 Revision by National Grid of merger savings in 2003

4.4.1 The original £100m savings estimate from National Grid was later revised to £135m in late 2003, when more detailed integration plans were being implemented. These savings were to be achieved by the end of 2004/05 financial year, at which point the separate identification of merger savings would cease. A breakdown by area of the business was also presented at this time (Table 4-1) and included in NG’s FBPQ submission.

Table 4-1: Breakdown of merger savings by business area Area Impacted £m

Corporate Centre 30

Information Systems 23

Business Services 17

Electricity Transmission 14

Procurement 24

Non-Regulated 18

Tax 4

Treasury 6

Total 135 Source: National Grid FBPQ submission

4.4.2 In its FBPQ submission, NG included some further details on the impact of merger savings on the business:

• “The new merged organisation underwent a period of rationalising duplicated activities, brought about by the combination of the existing NGET and NGGT organisations. Operations and Trading, Network Strategy and Engineering Services continued to fulfil the System Operator, Asset Manager and Service Provider roles respectively. The merger also created a new Commercial function that brought together key commercial groups previously embedded in the two organisations.” 69

• “Merger synergies were greatest in bringing together Corporate Centres and Support Functions activities. There was limited scope for synergies in Engineering Services, other than with support groups, due to the very different skill sets of the field forces. The net Transmission controllable operating cost reduction from merger synergies was around £30m comprising £14m of direct benefit coupled with

67 Credit Suisse First Boston report on NGT, 22 August 2003

68 USB (Europe) report on NGT, 7 November 2002

69 National Grid, FBPQ submission, 4.Consolidated Business Plan Narrative, pp5-6



a further £16m in respect of the services provided to Transmission by other Group functions.”69

4.5 Evidence of Merger Savings in Each Category

4.5.1 The absence of data for 2001/02 for Transco in NG’s response to the HBPQ was the main factor in limiting our ability to assess the savings arising from the merger. NG had notified Ofgem of the difficulty in obtaining data for Transco for 2001/02 in a way which is comparable to the remaining HBPQ responses. Ofgem agreed that NG did not have to submit 2001/02 data for Transco as part of its HBPQ submission.

4.5.2 As mentioned previously, the greatest scope for merger synergies was in the business services functions and the Corporate Centre. The HBPQ did not provide a further breakdown of synergies for each area of the business. The narrative frequently made references to merger savings, but did not breakdown the total cost reductions between merger synergies and non-merger activities (e.g. Staying Ahead corporate restructuring plan).

4.5.3 Therefore, the information provided by NG in its submissions was not sufficient to allow for an assessment of merger savings in individual business services. Given the importance of this issue, two meetings were held with NG in an attempt to quantify merger savings. The information provided in this section was supplied by NG in a presentation to Ofgem on 3 February 2006.

4.5.4 In our meetings with NG, it was noted that there were a number of difficulties in trying to quantify the merger savings.

• Distinction between restructuring and merger: both NGC and Transco began developing restructuring plans in January 2002. These plans were then adjusted to take account of the merger following the announcement in April 2002. This makes it difficult to distinguish between merger savings and those planned under restructuring.

• Baseline for comparison: establishing a baseline for what would have happened to the operational costs of the individual companies had they not merged has not been done. This is related to the previous point on distinguishing restructuring and merger savings.

• No direct link to current structure: certain functions within the business were previously embedded in different groups and are now run from a central business service. This means that it is not possible to track these costs over time and quantify savings made in these areas.

• Avoided cost increases as savings: avoiding cost increases can be considered a benefit from merging two companies (i.e. greater buying power can lead to lower price contracts). However, these avoided costs are not quantified in annual cost data since they do not occur.

• Timing of savings: certain merger savings can be made in a short period of time (e.g. eliminating duplicate roles within the organisation). However, other savings related to the merger can take longer to materialise. NG chose to cease identifying merger savings separately after 31 March 2005.

4.5.5 On the 3 February 2005, NG presented a summary of the savings achieved by business service function since 2001/02 using the HBPQ submission as the basis for the analysis. There were three distinct categories for tracking savings, as shown below.



• Clear mapping to 2001/02 costs: in these areas, there were equivalent functions in NGC and Transco, therefore a direct comparison of 2004/05 costs can be made to the sum of 2001/02 costs for the two organisations.

• Clear mapping to 2002/03 costs: for these functions, there is no comparable data for 2001/02, but savings can be traced back to the merged organisation cost base in 2002/03.

• Mapping of costs not possible: some functions cannot be traced back to 2001/02 or 2002/03 because of the organisational changes that have taken place over the last three years. These functions were subject to specific consideration and are discussed in more detail further on in this section.

4.5.6 Table 4-2 shows the savings in business services that fall into the first two categories, as presented by NG. A total of £93.3m was identified relative to the 2001/02 and 2002/03 cost base. The two largest areas were the Corporate Centre and IS, which together represent over 78% of the savings identified.

Table 4-2: NG summary of merger savings in Business Services

Source: National Grid, presentation to Ofgem 3 February 2006

4.5.7 The following functions were subject to specific consideration by NG in trying to identify the savings achieved since the merger. These figures have been obtained through discussions with people within the business and are NG’s best estimate.

• SHES: this did not exist as a consolidated function before 2004/05, so there is no reference point for comparison. NG has estimated the costs in 2003/04 for SHES to be £16.5m, which gives a saving of around £5m.

• Regulation: NGC and Transco had two different models for Regulation – the centralised function for NGC was adopted following the merger. Savings from 2001/02 costs (not presented by NG) would include significant Transco regulation activity resulting from the price control review. NG has estimated that savings in this area are equal to £2.9m.

• HR & Scheme Trainees: the data submitted in the HBPQ combines the core HR function costs with centrally held costs, including scheme trainees. According to NG, HBPQ Appendix 3 (paragraph 136) highlights £2.5m of savings made since 2002/03. NG estimates that around £2.0m of these are merger specific.

• Insurance: both NGC and Transco Insurance departments were of a similar size. According to NG, the current combined department is no larger than NGC’s old



department, with the implied staff related savings estimated at £0.2m. NG also noted that “any potential merger savings associated with the combined market power of the new organisation swamped by Insurance market price increases.”

• Operational Telecoms: given the different requirements and technologies used to monitor the electricity and gas networks, NG has assumed no merger savings in this area.

4.5.8 Table 4-3 summarises the analysis conducted by NG of merger savings in the business services area using the HBPQ submission. The gross savings identified by NG amount to just over £100m. However, we note the following issues with this approach.

• it does not distinguish between merger and planned restructuring such as Staying Ahead – this means that not all costs included here can be attributed to merger savings;

• in certain areas, it does not account for the sum of the two pre-merger organisations – savings reported are from 2002/03 which are likely to exclude savings made from the 2001/02 base year;

• it does not account for avoided cost increases as a result of the merger – this is difficult to quantify but NG claim that they exist; and

• it only focuses on business services – this was the main driver for merger savings and the focus of the workshop but NG has not presented analysis of other areas of the business.

Table 4-3: NG summary of merger savings in Business Services

Source: National Grid, presentation to Ofgem 3 February 2006

4.5.9 We are aware that a high level analysis has been carried out by NG of merger savings for the whole business. This was used to support its announcement to financial institutions in the City that the planned £135m savings had been achieved. This analysis was reviewed by PwC did not raise any objections to the work done. We have requested a copy of this analysis but have not received it to date.

4.6 Implications for Savings Achieved

4.6.1 NG has used its analysis of merger savings based on the HBPQ data to estimate the level of savings that can be attributed to the Transmission business. This was done by identifying savings as movements in costs of electricity and gas businesses separately.



For electricity, these movements in costs have been calculated as the difference between the costs allocated to the electricity business in 2004/05 and NGC costs in 2001/02 (if available) or 2002/03 costs allocated to electricity.

4.6.2 For gas costs, a similar process was used to estimate savings of the gas business (transmission, distribution and non-regulated business). Therefore, the 2004/05 costs for the gas business were compared with Transco costs in 2001/02 (where available) or 2002/03 costs allocated to gas business.

4.6.3 As discussed previously, certain business services function costs did not have a clear mapping of costs back to 2001/02 or 2002/03. For SHES and Regulation, NG has allocated the costs entirely to the gas businesses and stating that the reorganisation that took place in these two areas was all about restructuring the gas business. For HR and Insurance, the costs were split 50% to each area in the absence of better information.

4.6.4 The next step was to assess what proportion of these savings could be allocated to the Transmission business for electricity and gas:

• Electricity: as well as electricity Transmission, electricity costs are also allocated to UK Electricity Services, Interconnectors and Business Development. These account for only 5% of the costs allocated. Therefore, in NG’s analysis, 95% of the savings for electricity were attributed to the electricity Transmission business.

• Gas: the allocation of savings to the gas Transmission business was carried out using raw data from the Transaction Model. NG analysed how consistent the allocation of gas costs to Transmission was over time. Taking the overall costs, there was a consistent weighted average percentage of gas costs being allocated to Transmission of 16% between 2001/02 and 2004/05. Therefore, in NG’s analysis, 16% of the savings for gas were attributed to the gas Transmission business.

4.6.5 Table 4-4shows a summary of the analysis conducted by NG to identify merger savings in the Transmission business. We note that savings in Procurement, Tax and Treasury announced in late 2003 by NG have not been included in this analysis.

4.6.6 The results presented by NG indicate that up to £37m in cost reductions resulting from the merger (out of £103m) can be allocated to the transmission business (both gas and electricity). The majority of these savings come from business services (65%) and Corporate Centre (22%). NG’s analysis also indicates that only £5m (13%) of savings have been achieved in the UK Transmission business from merging the gas and electricity activities.

4.6.7 This analysis shows that savings in Corporate Centre, IS and Business Services have exceeded the company’s initial expectations. These areas were expected to deliver around half the merger savings and appear to have delivered almost two thirds. This demonstrates that NG has managed to extract significant merger savings in its support services. This view is also supported by the benchmarking analysis which shows the support functions as being broadly efficient.

4.6.8 Another issue raised from this analysis is that savings in the electricity transmission business appear to have fallen short of initial expectations. This could be due to upwards cost pressures in this area of the business. Alternatively, NG may have focused its merger savings effort on business support functions and less on the operating units of the business.



Table 4-4: Allocation of HBPQ merger savings analysis to Transmission

£m Forecast in 2003

NG PCR analysis

Savings allocated to Electricity

Savings allocated to Electricity Tx.

Savings allocated to Gas

Savings allocated to Gas Tx.

Total Tx. savings (gas and electricity)

Corporate Centre 30 39 4 4 18 4 8

IS 23 33 5 28

Business Services 17 31 13 17

18 7 24

Sub-total 70 103 22 21 64 11 32


14 5

5 5 - - 5

Procurement 24 24

Non-Regulated 18 18

Tax 4 4

Treasury 6 6

Could not be quantified using HBPQ data

Total 135 160 27 26 64 11 37

Source: National Grid, presentation to Ofgem 21 February 2006; Tx. = Transmission

4.6.9 We note that the proportion of merger savings from Corporate Centre, IS and Business Services allocated to Transmission is 31% (£32m out of £103m). In the HBPQ, the proportion of Business Services controllable costs allocated to Transmission is 39% (£123m out of £313m, which includes IS, Property and Insurance costs). If this higher proportion were used to allocated savings to the Transmission business, they would total £40m (i.e. £8m more). There are a number of reasons that may account for this difference:

• Savings allocated to the gas business only: for Regulation and SHES (£2.9m and £5.1m saving respectively) NG has allocated the savings entirely to the gas business. The justification for this is that these savings were realised mainly through the reorganisation of the gas business. The allocation to the gas transmission business used the historical weighted average cost split for all business support services, estimated at 16%.

• Allocation of Corporate Centre cost to Transmission: the proportion of costs allocated to the Transmission business has increased over the period 2002/03 to 2004/05. Therefore the decrease in Corporate Centre costs allocated to transmission has been lower than for the overall costs of the function.

• Specific IS projects for Transmission: there were a number of specific IS projects over the last four years that have been allocated to the Transmission business. This explains why the decrease in IS costs allocated to Transmission has been lower than for the overall IS function costs.

4.7 Implications for any Savings Still to be Achieved

4.7.1 NG assert that they have made all available merger savings, although they recognise that it is in practice difficult to separate continuing efficiency savings from merger savings. There has been no separate accounting of merger savings since 31 March 2005.

4.7.2 Nevertheless, it is clear that in practice there are savings that will be made in the future resulting from the merger. An example of this is the replacement of the three finance IT systems (one of which is a legacy from Transco) by one single company wide ERP system. NG has argued that multiple systems existed before the merger, therefore implementing a single ERP system can be considered as part of ongoing cost savings.



However, it is clear that savings arising from the replacement Transco’s finance system are in some way related to the merger.

4.8 Overall view

4.8.1 The absence of a complete dataset in the HBPQ for Transco covering 2001/02 has not allowed us to conduct our own analysis of merger savings. This section has mainly referred to analysis carried out by NG, using the HBPQ as a reference and has gone some way to address the data issue.

4.8.2 It is clear from the HBPQ that merger savings have occurred, in particular for business support services over the 2002/03 to 2004/05 period. Savings in Corporate Centre, IS and Business Services appear to have exceeded NG’s initial merger savings expectations. Therefore, it would appear that NG has managed to extract the bulk of merger savings from these areas.

4.8.3 The analysis and data presented by NG does not allow for a “no-merger” scenario to be constructed. Therefore, we are not able to identify how far costs would have changed if the merger had not taken place. Certain savings would probably have been achieved if the merger between NGC and Transco had not taken place. However, it is clear that there are other areas (e.g. Corporate Centre) where the majority of the savings since 2001/02 can be directly attributed to the merger.



5 Workstream C: Top-Down Efficiency Assessment

5.1 Introduction and scope of work

5.1.1 This section of the report provides analysis to inform Ofgem’s judgements on the overall efficiency of operating costs incurred by the transmission businesses. As such it complements the more detailed benchmarking work carried out for shared services in Workstream B and the studies of operating cost efficiency being carried out by other consultants.

5.1.2 We have examined three main sets of benchmarks and trends. First, we have studied long term trends in controllable operating costs for gas and electricity transmission, including the effects of the NGC Transco merger. This analysis is based on information in regulatory accounts.

5.1.3 We have also analysed productivity gains in other sectors, by examining trends in unit operating costs in the UK in electricity distribution, transmission, water, sewerage, telecommunications and rail.

5.1.4 Finally, we compared NGET with other electricity transmission companies in Europe and the USA, and with Scottish transmission companies. Suitable data was not readily available to carry out similar comparisons for gas. This issue is discussed further later in the section.

5.1.5 Extensive data gathering has been required to conduct the analysis of trends and benchmarks. This data is taken from a variety of sources, specified in the individual sections.

5.2 Time trends for NG’s businesses

Electricity Transmission70

5.2.1 Controllable costs from the HBPQ and regulatory accounts for electricity transmission71 are shown in Figure 5-1 and Figure 5-2. The first figure shows the whole of the period since the introduction of incentive regulation. The second figure emphasises the period of the most recent price control and shows the timing of the NGC Transco merger.

5.2.2 The graph shows four sets of data.

• Controllable operating costs from the HPBQ.

• HBPQ controllable costs adjusted to include various costs72 designated in the HBPQ as non-controllable. This is equal to the HBPQ total operating costs excluding depreciation, rates and balancing services scheme direct costs.

• Controllable costs from the regulatory accounts. The regulatory accounts do not specifically break down operating costs into controllable and non-controllable costs. We designated payroll and other operating charges as controllable costs, and all other operating costs73 as non-controllable costs. This total closely matches

70 A similar analysis for ECOC is performed in Section 4 of Workstream A, entitled “Historical ECOC”.

71 This includes both ETO and internal ESO controllable costs.

72 Specifically, these are ETO and ESO transmission licence, pension surplus/deficit and excluded

services costs, as well as “other” costs from ETO. See Table 2-8, “Reconciliation on NGET operating costs to regulatory accounts for 2004/05” for more details on this reconciliation. 73 These consist of depreciation, rates, purchases of electricity and balancing/transmission services

scheme direct costs.



the adjusted HBPQ controllable costs from the regulatory accounts, thus achieving a reconciliation with the HBPQ.74.

Figure 5-1: Historical analysis of electricity transmission controllable costs (1990/91 – 2004/05)

0

100

200

300

400

500

600

90/91 91/92 92/93 93/94 94/95 95/96 96/97 97/98 98/99 99/00 00/01 01/02 02/03 03/04 04/05

Financial Year End

£'m

(2004/5 prices) *


HPBQ total operating costs less rates, depreciation and non-controllable system operatorcostsRegulatory accounts controllable costs for transmission (payroll and other costs)

Merger

Beginning of

previous price control period

* The conversion rate used in converting nominal prices into 2004/05 prices was the RPI for September in each year. This convention is used throughout the section and is consistent with that used in the section covering Workstream B. Source: NGET regulatory accounts; HBPQ. Deloitte analysis.

74 The large difference in 2003/04 is due to the extra £8.1m included in the regulatory accounts’ operating

costs, which do not appear in the HBPQ operating costs. The absence of these costs from the HBPQ is due to group and FRS20 adjustments.



Figure 5-2: Historical analysis of electricity transmission controllable costs (1997/98 – 2004/05)

0

50

100

150

200

250

300

97/98 98/99 99/00 00/01 01/02 02/03 03/04 04/05

Financial Year End

£'m (2004/5 prices)


HPBQ total operating costs less rates, depreciation and non-controllable system operatorcosts

Regulatory accounts controllable costs for transmission (payroll and other costs)

Merger

Beginning of

previous price control period

Source: NGET regulatory accounts; HBPQ. Deloitte analysis.

5.2.3 Figure 5-1 shows that NGET has experienced a marked decline in controllable transmission costs since privatisation in 1991, with controllable costs falling by 55% between 1991 and 2005. The initial peak in 1991/92 is understood to be due to the significant restructuring costs incurred by NGC immediately following privatisation. From 1999/2000 onwards, controllable costs have decreased more slowly. This is shown in more detail in Figure 5-2. The reduction in controllable operating costs in each five year period is summarised in the table below.

Table 5-1: Compound annual percentage reduction in operating costs

Source: NGET regulatory accounts; HBPQ. Deloitte analysis.

Gas Transmission

5.2.4 A similar reconciliation of the published regulatory accounts with the HBPQ was performed for gas transmission from 1996 onwards. As for electricity transmission, controllable costs were defined as total operating costs less depreciation, rates, replacement expenditure, gas purchases and exceptional items75.

5.2.5 In the regulatory accounts, operating costs are only recorded for transportation services76 as a whole. Furthermore, prior to 2001, transportation services’ operating costs in the regulatory accounts are inclusive of metering services77. From 2001 onwards, these services are recorded separately.

75 Exceptional items include restructuring and demerger costs, as well as exceptional operating items.

76 Transportation refers to both transmission and distribution services, as well as metering services.

77 Metering services refers to both metering and meter reading services.

90/01 – 94/95 94/95 – 99/00 99/00 – 04/05

Real terms -7.1 -4.5 -4.2

Nominal terms -4.4 -2.6 -1.8



5.2.6 In order to strip out metering operating costs between 1996 and 2000, we estimated the average ratio of metering costs to transportation operating costs between 2001 and 2005, and then removing this proportion from transportation operating costs recorded before 2001.

5.2.7 We were unable to remove distribution costs from the transportation services costs recorded in the regulatory accounts, as the changing proportion of distribution and transmission costs making up transportation services is not clear.

5.2.8 We compared the controllable costs for distribution and transmission derived in this way from the regulatory accounts with controllable costs recorded in the HBPQ78. We note that this comparison is imperfect, due to the lack of comparability between the HBPQ and regulatory accounts, and the presence of distribution costs in transportation services.

5.2.9 Figure 5-3 shows controllable operating costs for gas distribution and transmission, as reported in the regulatory accounts, and for gas transmission, as reported in the HBPQ. As with electricity transmission, most of the large gains following privatisation occurred before 1999.

Figure 5-3: Historical trend analysis of gas transmission controllable costs (HBPQ) and gas transmission and distribution controllable costs (regulatory accounts)

0

200

400

600

800

1000

1200

1996 1997 1998 1999 2000 01/02* 02/03 03/04 04/05

Year End

£'m (2004/5 prices)

Regulatory accounts transmission and distribution controllable costs

HBPQ transmission controllable costs

merger

* The year end was adjusted from 31 December to 31 March in 2000/01. We have adjusted the resulting 15 month financial period to a 12 month period, on a proportional basis. Source: Transco and NG regulatory accounts, HBPQ. Deloitte analysis.

5.2.10 The cost savings in each service are shown in the table below. There is a decrease of around 7.6% in transportation (transmission and distribution) controllable costs after the merger, which is larger than the decrease of 3.4% in transmission controllable

78 These controllable costs are for both GTO and GSO.



costs. This appears consistent with NG’s allocation of more of the savings from the merger to distribution than to transmission79.

Table 5-2: Compound annual percentage reduction in operating costs 95/96-01/02 02/03-04/05

Transmission, real terms -3.4%

Transmission nominal terms -2.3%

Transportation (transmission and distribution), real terms

-2.8% -7.6%

Source: Transco and NG regulatory accounts, HBPQ. Deloitte analysis.

5.2.11 Also of interest is a reconciliation between the statutory accounts and the HBPQ,

particularly as it is possible to separate out transmission from transportation costs using these accounts. This is demonstrated in Figure 5-4 below.

5.2.12 Figure 5-4 shows that gas transmission operating costs from the HBPQ reconcile closely with transmission operating costs (less exceptional items) from the statutory accounts. Using the average ratio of controllable to uncontrollable operating costs given in the HBPQ for 2002/03 to 2004/05, we estimated controllable costs from the transmission operating costs recorded in the statutory accounts for 2000 and 2001/02. We used operating costs less exceptional items from the statutory accounts for this calculation, as operating costs in the HBPQ are recorded without the addition of exceptional costs.

5.2.13 Part of the trend in operating costs for the business as a whole is due to the presence of exceptional items. In Figure 5-4, some of the exceptional costs have been significant, and their inclusion may have contributed to the sporadic large fluctuations in cost reductions year on year.

5.2.14 The proportion of controllable costs making up operating costs is an average derived from actual data for 2002/03 to 2004/05, so estimates of controllable cost movements in 2000 and 2001/02 will not reflect any changes in the ratio of controllable to non-controllable costs that may have occurred in these years.

79 These savings were mostly found in shared services.



Figure 5-4: Historical trend analysis of gas transmission controllable costs from the statutory accounts and the HBPQ

0

50

100

150

200

250

300

350

400

2000* 01/02 02/03 03/04 04/05

Year End

£'m

(2004/05 prices)

HBPQ controllable costs

HBPQ operating costs

Statutory a/c controllablecosts (withoutexceptional items)

Statutory a/c operatingcosts

Statutory a/c operatingcosts (withoutexceptional items)

merger

* The year end was adjusted from 31 December to 31 March in 2000/01. We have adjusted the resulting 15 month financial period to a 12 month period, on a proportional basis. Source: Transco and NG statutory accounts, HBPQ. Deloitte analysis.



Price control projections vs. actual performance

5.2.15 Figure 5-5 and Figure 5-6 below show the actual performance of the electricity and gas TO controllable operating costs80 relative to the Ofgem allowance.

5.2.16 For NGET, we have examined performance during the price control relative to that in 1999/00. We have used the mid-range of Andersen’s adjusted ECOC in their review of NGC’s operating costs at the last price control as our base value.

Figure 5-5: Electricity TO controllable operating costs – historical actual v. allowance

0.0

50.0

100.0

150.0

200.0

250.0

300.0

1999/00 2001/02 2002/03 2003/04 2004/05Year End

£'m

(2004/05 prices)

ActualPerformance

OfgemAllowance

Source: Andersen and price control performance data.

Figure 5-6: Gas TO controllable operating costs – historical actual v. allowance

0.0

20.0

40.0

60.0

80.0

100.0

120.0

2002/03 2003/04 2004/05

Year End

£'m (2004/05 prices)

ActualPerformance

OfgemAllowance

Source: Price control performance data from HBPQ

80 In this case, controllable operating costs allowed by Ofgem are the efficient cash operating costs (ECOC). A reconciliation between accounting operating costs and ECOC are described in Workstream A, section , ‘NG’s adjustments to accounting operating costs to obtain ECOC’.



5.2.17 Electricity TO controllable operating costs were broadly in line with the Ofgem allowance. However, actual expenditure exceeded the allowance by £14.9m and £32.2m in 2001/02 and 2002/03 respectively, then fell below the allowance by £9.4m in 2003/04, before rising above the allowance against by £5.3 million in 2004/5.

5.2.18 For gas transmission, shown in Figure 5-6, actual expenditure has been significantly below Ofgem’s allowances at the last price control. NG explains this as being primarily due to an over-allocation of costs to the Transmission Owner (offset within the National Grid Gas price control by an under-allocation to the distribution business) at the last price control.

5.2.19 Over the period of the price control, NG’s gas transmission costs have shown a steady decrease.

5.2.20 The differences between target and out-turn operating costs for both gas and electricity are shown in the table below:

Table 5-3: Comparison of target and out-turn operating costs

Ofgem target Achieved out-turn Difference

Electricity transmission

Electricity total (£m, 2004/05 prices) 777.0 820.0 -43.0

Electricity NPV at 6.25% (£m, 2004/05 prices)

671.6 710.4 -38.9

Electricity % change during price control (annualised rate)

-4.4% -5.6% 1.3%

Electricity percentage change from 1999/2000 (annualised rate)

-8.8% -8.1% -0.7%

Gas transmission

Gas total (£m, 2004/05 prices) 291.5 185.6 105.9

Gas NPV at 6.25% (£m, 2004/05 prices) 258.7 164.8 93.9

Gas % change (annualised rate) -1.2% -3.0% 1.8% Source: HBPQ, Deloitte analysis.

5.2.21 Table 5-3 shows that NGET has underperformed the price control allowances for

controllable operating costs, both in terms of total operating costs and net present value of operating costs.

5.2.22 From the annual rate of cost reduction, it would appear that NGET had exceeded the expectations of the price control. However, this is only due to NGET’s higher starting levels of costs in 2001/02. When cost reductions are looked at from the starting point of the adjusted base year, NGET’s annual reductions of 8.1% are less than those expected by the price control of 8.8%.

5.2.23 NGG has outperformed the price control, both in terms of annual cost reductions and overall costs. It is difficult, though, to draw many conclusions from this due to the alleged over-allocation of costs to transmission.



5.3 Comparisons with other privatised infrastructure companies

5.3.1 The focus of this section is quantitative evidence on the productivity performance of companies that may be deemed comparable to NG.

5.3.2 A comprehensive measure of productivity performance is provided by total factor productivity (TFP), which measures the efficiency with which companies use all the inputs in their production processes to produce outputs. It takes into account all the factors of production (e.g. labour, capital and raw materials) used to produce the goods and services, so as to isolate the change in output that is not explained by changes in inputs. TFP indices provide a way of comparing the efficiency with which companies use their inputs.

5.3.3 However, there are many difficulties associated with compiling meaningful TFP indices, particularly with regard to the capital input used. For this reason, partial factor productivity (PFP) measures are often used when examining the efficiency of utilities.

5.3.4 PFP compares the ratio of a single output to a single input across firms and over time. An example of a PFP index is unit operating costs.

5.3.5 Partial productivity measures can be misleading, as they are sometimes impacted by factor substitution effects - for example, if capital expenditure is substituted for operating expenditure, a decline in unit operating costs will result. Due to the difficulty of obtaining valid TFP indices, however, and the scope of our analysis as determined by Ofgem, we concentrate on the PFP measure of real unit operating expenditure. This is in line with other studies on regulated utilities.

Comparison of RUOE trends

5.3.6 The focus of this section is an analysis of operating cost trends in comparator

industries to NG. This is to assist in identifying the scope for operating efficiency improvements over the control period for NG.

5.3.7 The choice of the comparator industries is based on two criteria:

• the provision of network infrastructure services - network industries share similar characteristics, such as increasing returns to scale and density, and the long-term effects of past investment on current efficiency levels; and

• the industry is subject to economic regulation.

5.3.8 Based on these criteria, the industries selected are electricity distribution and transmission, water, sewerage, telecommunications and rail. All of these industries have been privatised since 1984, and have been subject to some form of RPI-X regulation since privatisation.

5.3.9 There are physical difference between the type of activities undertaken by NG and those of its comparators. However, this analysis is to determine operating cost-reduction trends rather than the level of operating costs.

5.3.10 We have built on the work undertaken for OFGEM81 (Europe Economics, 2001), the Office of Water Services (OFWAT)82 (Europe Economics, 2003) and the Office of the Rail Regulator (ORR)83 (Oxera, 2003), using their methodology in order to compare the performance of NGET against other privatised companies since their privatisation. In

81 2001, Europe Economics, ‘Top-down study’, Appendix D of the Transco Price Control Review by

Mazars Neville Russell, September. 82 2003, Europe Economics, “Scope for Efficiency Improvement in the Water and Sewerage Industries,” a

report for Ofwat, March. 83 2003, Oxera, “Operating cost reductions in regulated network industries.” June.



most cases, we have carried out our own analysis for the entire period examined, to ensure consistency of results. In some cases, due to difficulties in obtaining original data for earlier years, we have extended their analysis up to 2004/5.

5.3.11 The measure of performance is percentage change in Real Unit Operating Expenditure (RUOE). The Compound Annual Growth Rate (CAGR) in RUOE over the period since privatisation is also reported.

5.3.12 RUOE for each company has been determined from the operating costs reported in their Annual Report and Accounts and from data provided by the companies. Calculation of RUOE involves dividing the real operating expenditure in a year by an appropriate output measure. The base year used is 2004/5.

5.3.13 To derive operating expenditure, we have subtracted depreciation from the operating costs reported in the accounts.

5.3.14 There are limitations on the data used, in that company Annual Reports and Accounts do not always report operating expenditure clearly for our purpose. Relevant output measures are also not always available.

Methodological issues

5.3.15 Exceptional items have been included in the figures for operating expenditure. Although their inclusion can lead to the occasional anomalous observation in individual years, excluding them could create an upward bias on cost savings. This is especially relevant since exceptional costs are often associated with internal restructuring or a merger. They can therefore be seen as an investment resulting in subsequent cost reductions.

5.3.16 Historic cost adjustments may need to be adjusted if input price growth is significantly different between industries and over time. Given that the focus of this study is operating expenditure, the main input factor is labour. It is assumed that there is no significant difference in wage pressure across the industries examined.

5.3.17 In light of the fact that many network industries experience increasing returns to scale, we have adjusted our RUOE figures for the effects of scale economies. Increasing returns to scale imply that, as the scale of production increases, output grows by proportionally more than the corresponding increase in the inputs. Without adjusting for this effect, calculated reductions in RUOE can be misleading as the apparent improvement in efficiency could actually be due to the growth in inputs.

5.3.18 We have adopted the methodology used by Oxera (2003) in their report to the ORR to correct for non-constant returns to scale. The returns-to-scale correction adjusts the RUOE of the first year of each time period examined, using the following equation:

( ) tCQtt

real

t

corrected

t OGCRUOE /1 ,111 ε×∆+×= −−−

where C is real costs, ttG ,1−∆ is the percentage change in output levels in the period

examined, CQε is the elasticity of costs with respect to output and O is output level.



Network Rail Infrastructure

5.3.19 The rail network infrastructure of the former British Rail is currently operated by Network Rail, which took over the responsibilities of Railtrack PLC in 2002 after Railtrack was placed into Administration in 2001. After acquiring Railtrack, Network Rail renamed the business Network Rail Infrastructure (NRI).

5.3.20 Since privatisation in 1996, the infrastructure operator has been subject to government regulation.

5.3.21 Two potential measures of output exist for NRI: track route open for traffic and passenger kilometres. Track route is track managed by NRI, and does not include track managed by private companies. Passenger kilometres are estimated from ticket sales and are essentially the total passenger distance travelled over the network in a year.

5.3.22 Data on both these measures is available from privatisation in 1996. However, a change in the methodology used to calculate both track route and passenger kilometre statistics from 2004/05 onwards means comparisons between this and previous years must be made with caution.

5.3.23 Between 1994/95 and 2004/05, passenger kilometres have increased by 48%, from 28.7 to 42.4 billion kilometres, but track route has decreased by 2.5%. Even without the change in measuring methodology in 2004/05, track route has remained basically constant over the period.

5.3.24 For this reason, neither of these output measures may be wholly appropriate. Europe Economics (2001) argues that the large increase in passenger numbers would probably have affected NRI’s costs, due to the increased number of trains running on its tracks, but this is not captured in track route figures. However, the impact on NRI’s costs will also probably not have been as large as the rise in passenger numbers, as some of the increase in passenger kilometres will have been absorbed by trains becoming fuller.

5.3.25 In light of this, the real figure for RUOE reduction is likely to lie somewhere in-between the two estimates given below in Table 5-4.

5.3.26 We have also reported scale adjusted RUOE reductions. Choice of an elasticity of scale coefficient is problematic, as few estimates exist for rail infrastructure alone. The little existing evidence is mixed. Cambridge Economic Policy Associates (CEPA, 2003)84discusses various empirical studies into return to scale in rail infrastructure, and conclude that a scale elasticity of 0.9 is reasonable.

842003, Cambridge Economic Policy Associates, ‘Productivity Improvements in Distribution Network

Operators’, a report to Ofgem, November.



Table 5-4: Annual RUOE reductions (%) between 1994/95 and 2004/05 – Network Rail Infrastructure

RUOE reductions RUOE reductions adjusted for

scale

Output measure Passenger kilometres

Track route Passenger kilometres

Track route

1994/95 – 1995/96 -7.9 -4.4 -7.5 -4.4

1995/96 – 1996/97 -2.6 4.2 -1.9 4.2

1996/97 – 1997/98 -13.2 -6.1 -12.5 -6.1

1997/98 – 1998/99 -5.8 -1.4 -5.4 -1.4

1998/99 – 1999/00 -6.9 -1.2 -6.4 -1.2

1999/00 – 2000/01 -4.9 -5.7 -5.0 -5.7

2000/01 – 2001/02 39.6 42.9 39.9 42.9

2001/02 – 2002/03 14.2 15.8 14.4 15.8

2002/03 – 2003/04 3.0 7.3 3.3 7.2

2003/04 – 2004/05 -10.3 -4.8 -9.9 -5.0

Change in RUOE(%)

-4.2 45.3 -1.0 44.9

CAGR (1994/95 – 2004/05)

-0.4 3.8 -0.1 3.8

Source: Network Rail Infrastructure annual reports; Strategic Rail Authority performance statistics; cost data for the period 1994 to 2000 is taken from Europe Economics (2003). Deloitte analysis.

5.3.27 From Table 5-4, it can be seen that the calculated RUOE reductions vary considerably depending on the output measure suggested, as would be expected. As the track route figures do not show any substantial change over the period, the figures on this basis are essentially total cost figures, in real terms.

5.3.28 The overall RUOE reduction in terms of passenger kilometres is 4.2%, compared to an increase in RUOE in terms of track route of 45.3%. The poor efficiency performance thus recorded is mostly due to the large amount of maintenance expenditure needed after 2002, when Network Rail acquired the business.

5.3.29 Due to a break in the series following the Hatfield accident, we have also calculated RUOE estimates from 1995/96 and from 2001/02. These are shown in Table 5-5 below:

Table 5-5: Annual RUOE reductions (%) from 1994/95-2001/02 and 2001/02-2004/05 – Network Rail Infrastructure

RUOE reductions RUOE reductions adjusted

for scale

Output measure Passenger kilometres

Track route Passenger kilometres

Track route

CAGR 2001/02 - 2004/05 1.8 5.8 2.1 5.6

CAGR 1994/95 - 2001/02 -1.4 3.0 -1.0 3.0 Source: Network Rail Infrastructure annual reports; Strategic Rail Authority performance statistics; cost data for the period 1994 to 2000 is taken from Europe Economics (1999). Deloitte analysis.

5.3.30 Without the exceptional costs incurred in 2001/02, the rail industry’s performance can

be seen to have improved between 1994/95 and 2001/02 for both output measures, but has worsened between 2001/02 and 2004/05, possibly due to the expanded investment programme and increased operating costs in these years.



5.3.31 As is noted by CEPA (2003), however, the recent history of the rail industry makes it very different from both electricity and gas transmission. The history of under-investment, followed by the large investment programme after a series of accidents, means that little weight should be placed on these results in determining expected efficiency change for NG.

Telecoms: BT

5.3.32 British Telecom (BT) was privatised in 1984. Due to the high pace of technological innovation in the telecommunications sector since then, BT’s long-term productivity performance may surpass that of the other network industries, and so may not be that usefully comparable as a benchmark.

5.3.33 BT’s RUOE has been calculated using two measures: the total number of exchange line connections and call volume.

5.3.34 Of these two, call volume may be the more appropriate measure as the exchange line connections measure cannot reflect the increasing number of services provided through a single telephone connection, nor the network capacity provided.

5.3.35 Call volume is therefore also used as a measure of output.

5.3.36 In assessing BT’s RUOE, we have considered the regulated network segments of the business, and in particular have obtained data on the network, access and retail systems segments.

5.3.37 We have obtained all data on BT from its regulatory accounts, supplied to us by BT. However, we have used data only from 1997/8, as data is not available on a consistent basis before this.

5.3.38 Furthermore, data is not available for 2004/05, due to further changes in regulatory accounting guidelines, making comparisons impossible.

5.3.39 Operating costs have been taken as the sum of the operating costs for the three business segments identified above. Costs include depreciation, as the regulatory accounts do not separate out depreciation from operating costs for the separate segments. We have chosen to use BT’s regulatory, rather than statutory, accounts, as this gives us a way to separate out the activities of BT which occur outside the UK and as such are not related to the output measures we have chosen.

5.3.40 Europe Economics (2001) points out that it is possible that growing internet usage has increased BT’s costs without there being a corresponding increase in the number of connections. This could lead to the underestimation of the overall reduction in RUOE of BT.

5.3.41 Also of note when examining BT’s RUOE reductions are economies of scale. During the time period under examination, BT experienced large output growth of approximately 14% per annum. Following the methodology used by Oxera (2003), we have assumed BT’s elasticity of scale is equal to 0.9.



5.3.42 Annual RUOE reductions can be seen in Table 5-6 below.

Table 5-6: Annual RUOE reductions (%) between 1997/98 and 2003/04 - BT RUOE reductions RUOE reductions adjusted

for scale

Output measure Call volume Exchange line

connections

Call volume Exchange line

connections 1997/98 – 1998/99 -5.1 -0.9 -4.6 -0.7 1998/99 – 1999/00 -2.4 6.2 -1.4 6.3 1999/00 – 2000/01 -13.9 1.6 -12.5 1.7 2000/01 – 2001/02 -7.6 8.8 -6.1 8.9 2001/02 – 2002/03 -15.8 -3.3 -14.8 -3.4 2002/03 – 2003/04 -3.8 -2.8 -3.8 -3.0 Change in RUOE(%) -40.3 9.3 -37.4 9.5 CAGR (1997/08-2003/04) -8.2 1.5 -7.5 1.5

Note: Operating costs include depreciation. The operating cost figures used to calculate RUOE include access, network and retail costs. Call volume includes local, national, international and fixed-to-mobile calls and other calls (operator calls, speaking clock, number translation services, DQ, premium rate and calls to Internet service providers). Source: BT regulatory accounts; Ofcom and archived Oftel market information; Deloitte analysis.

5.3.43 The results show that BT’s estimated annual RUOE reduction over the whole period of

the analysis is approximately 7.5%, using scale adjusted call volume as the preferred output measure.

5.3.44 When exchange line connections are used as the output measure, RUOE instead increases by an estimated 1.5% annually. This is likely to be due to increased internet usage, as discussed above.

5.3.45 In order to take into account all possible measures of BT’s output, we have also aggregated the estimated RUOE reductions of call minutes and exchange line connections. Shares of revenue have been used to assign weights to each output85. These are 75% for call volume and 25% for exchange line connections, estimates based on O’Mahony (1997)86

Table 5-7: Annual RUOE reductions (%) between 1997/98 and 2003/04 using a composite output - BT

RUOE reductions RUOE reductions adjusted for scale

1997/98 – 1998/99 -4.0 -3.6 1998/99 – 1999/00 -0.2 0.5 1999/00 – 2000/01 -10.0 -8.9 2000/01 – 2001/02 -3.5 -2.4 2001/02 – 2002/03 -12.7 -12.0 2002/03 – 2003/04 -3.5 -3.6 Change in RUOE(%) -27.9 -25.7 CAGR (1997/98-2003/04) -5.8 -5.2

Note: Operating costs include depreciation. The operating cost figures used to calculate RUOE include access, network and retail costs. Source: BT regulatory accounts; Oftel market information; Oxera analysis and Deloitte analysis.

85 Oxera (2003) note that the share of operating costs of each output would be the most accurate

weighting to use, but this information is generally unavailable. 86 O’Mahony, M., Oulton, N., and Vass, J. (1997), ‘Labour Productivity in Transport and Communications:

International Comparisons’, National Institute of Economic and Social Research, Discussion Paper No. 117, April.



5.3.46 Based on the composite output measure, the annual adjusted RUOE reduction over the entire period examined is 5.2%.

5.3.47 The use of these annual RUOE changes to inform possible cost-reduction targets for NGET could be considered inappropriate, given the technological progress of the telecommunications industry. However, composite output reductions, although over a shorter period falling well after the beginning of privatisation, are similar to those experienced by NGET.

Water and Sewerage

5.3.48 Since privatisation in 1989, the water and sewerage industry has been required to undertake substantial investments to meet quality and environmental standards. This has resulted in increases in operating expenditure over time associated with both increases in quality and volume. Simple comparisons of unit costs which ignore this effect understate the true rate of cost reduction.

5.3.49 To avoid this, we have concentrated on ‘base service’, which Ofwat define as the provision of existing levels of demand, service and quality. Base service operating expenditure is the level of operating expenditure on the network required to maintain the quantity and quality of outputs and levels of service provided by the water and sewerage services in the report year.

5.3.50 Base service operating expenditure was reset in 1997/8, so data is only reported from then on. Table 5-8 reports the change in real base operating expenditure from 1997/98 to 2004/05 as aggregated figures for the water and sewerage companies.

Table 5-8: Annual real base operating expenditure reductions (%) between 1997/98 and 2004/05 – water and sewerage services

Real base Opex reductions – water service (%)

Real base Opex reductions – sewerage service (%)

1997/98 – 1998/99 -3.1 -0.2 1998/99 – 1999/00 -0.1 -0.1 1999/00 – 2000/01 -8.8 -9.1 2000/01 – 2001/02 -1.4 -1.1 2001/02 – 2002/03 -0.3 2.5 2002/03 – 2003/04 0.3 0.7 2003/04 – 2004/05 -1.8 2.6 Overall change (%) -14.5 -5.0 CAGR (1997/98-2004/05) -2.2 -0.7

Note: Base Opex excludes depreciation, uncontrollable costs (local authority rates, Environmental Agency charges, etc), exceptional items and Opex on quality enhancement. Source: Ofwat, Deloitte analysis

5.3.51 Table 5-8 suggests moderate annual reductions in base service Opex in the water industry, approximately equal to 2.2%. Base service Opex annual reductions in the sewerage industry are smaller, around 0.7%.

5.3.52 We have not adjusted for returns to scale for either the water or sewerage industry, as by the definition of base services, the quantity of output is as recorded in the base year.

5.3.53 The above figures represent water and sewerage services as a whole, and so include ‘upstream’ and ‘downstream’ activities such as water abstraction, sewerage treatment etc., as well as the network elements (i.e. water distribution and the sewerage network). Ofwat has indicated that, in the initial years after privatisation at least, efficiency savings have been higher in the network elements than for the service as a whole87.

87 1999, Ofwat, ‘Financial Performance and Expenditure of the Water Companies in England and Wales’,

September.



Electricity Industry

5.3.54 In this section, we examine electricity distribution in the UK, Northern Ireland Electricity, the two Scottish transmission companies, Scottish Hydro and Scottish Power, as well as NGET.

Electricity Distribution

5.3.55 Electricity distribution in England, Wales and Scotland is carried out by 14 regional companies. These were formed from the previous Area Boards.

5.3.56 The data used for RUOE analysis comes from the companies’ regulatory accounts. However, due to disparate accounting practices between the companies prior to the 1998 reporting year, early data may contain significant inconsistencies.

5.3.57 Furthermore, in 1999/2000, there was a move from current-cost accounting (CCA) to historic-cost accounting (HCA) in the preparation of companies’ regulatory accounts. We have, however, elected to ignore this as the main impact on operating costs is on depreciation; as operating expenditure is operating costs less depreciation our RUOE calculations remain essentially unaffected.

5.3.58 As theory suggests that considerable economies of scale exist in this industry, the volume growth recorded since privatisation may introduce upward bias in the reported RUOE. We have therefore adjusted for this, using a scale elasticity estimate of 0.721. This was suggested by Oxera (2003) based on a study by Burns and Weyman-Jones88.

5.3.59 Table 5-9 shows the RUOE reductions for each distribution company since privatisation.

88 1994, Burns, P. and Weyman-Jones, T.G., ‘The Performance of the Electricity Distribution Business:

England and Wales 1971-1993’, Centre for the Study of Regulated Industries, Chartered Institute of Public Finance and Accountancy, May.



Table 5-9.i: Annual RUOE reductions (%) between 1990/91 and 2004/05 – electricity distribution

EDFE (LPN) – London Electricity

EDFE (EPN) – Eastern Electricity

CE Northern

RUOE reductions

Scale adjusted

RUOE reductions

Scale adjusted

RUOE reductions

Scale adjusted

1990/91 – 1991/92 -9.3 -8.7 -4.8 -4.3 1.2 1.6 1991/92 – 1992/93 -7.2 -7.5 3.0 3.0 -6.3 -6.0 1992/93 – 1993/94 -2.1 -1.8 1.0 1.4 10.3 11.0 1993/94 – 1994/95 13.3 13.4 -10.1 -10.1 2.8 3.0 1994/95 – 1995/96 -20.3 -19.2 -3.2 -1.9 -8.4 -7.7 1995/96 – 1996/97 -10.8 -10.0 -16.7 -16.3 -11.2 -10.7 1996/97 – 1997/98 -14.3 -14.1 -15.4 -15.4 -11.3 -10.8 1997/98 – 1998/99 -18.8 -18.0 -20.7 -20.0 -1.1 -0.4 1998/99 – 1999/00 10.2 11.6 12.8 13.2 -11.2 -10.5 1999/00 – 2000/01 -48.8 -48.1 -18.1 -17.5 -36.9 -36.4 2000/01 – 2001/02 -8.1 -7.3 -38.4 -38.0 -3.6 -3.4 2001/02 – 2002/03 -4.4 -3.8 22.8 24.2 -14.6 -13.9 2002/03 – 2003/04 5.8 6.5 9.4 9.4 -9.7 -9.3 2003/04 – 2004/05 -12.2 -11.6 -14.2 -13.7 -8.9 -9.0 Change in RUOE(%) -76.0 -73.9 -68.4 -66.3 -70.9 -68.9 CAGR (90/91-04/05) -9.7 -9.1 -7.9 -7.5 -8.4 -8.0 CAGR (00/01-04/05) -5.0 -4.3 -8.2 -7.7 -9.3 -9.0

EDFE (SPN) – Seeboard CN East – East Midlands

CN West - Midlands

RUOE reductions

Scale adjusted

RUOE reductions

Scale adjusted

RUOE reductions

Scale adjusted

1990/91 – 1991/92 -2.8 -2.4 -9.7 -9.2 -1.4 -1.2 1991/92 – 1992/93 4.5 3.7 -3.4 -3.3 -4.7 -4.5 1992/93 – 1993/94 -2.2 -2.3 2.5 3.0 -1.0 -0.3 1993/94 – 1994/95 -4.0 -3.9 -1.4 -1.0 -10.7 -10.3 1994/95 – 1995/96 -11.0 -10.1 -8.6 -7.6 -16.2 -15.4 1995/96 – 1996/97 -38.8 -38.5 1.8 2.2 -1.7 -1.3 1996/97 – 1997/98 5.0 5.1 0.1 0.5 -6.5 -6.1 1997/98 – 1998/99 6.4 7.1 4.2 5.0 -7.1 -6.5 1998/99 – 1999/00 -3.6 -2.5 6.8 6.9 -0.1 0.1 1999/00 – 2000/01 -27.9 -27.4 -20.7 -20.0 -11.0 -10.3 2000/01 – 2001/02 3.8 3.6 -34.4 -34.2 -14.7 -14.5 2001/02 – 2002/03 5.7 6.5 -8.1 -7.3 -10.3 -10.2 2002/03 – 2003/04 -14.2 -13.6 -14.2 -13.8 9.5 9.6 2003/04 – 2004/05 -14.3 -14.0 -8.6 -8.3 -26.0 -26.0 Change in RUOE(%) -67.5 -65.8 -65.8 -63.5 -67.6 -65.8 CAGR (90/91-04/05) -7.7 -7.4 -7.4 -6.9 -7.7 -7.4 CAGR (00/01-04/05) -5.2 -4.9 -17.1 -16.7 -11.3 -11.2

Note: Output is units of electricity distributed. Source: Ofgem; Company regulatory accounts; Deloitte analysis.



Table 5-9.ii: Annual RUOE reductions (%) between 1990/91 and 2004/05 – electricity distribution

United Utilities - Norweb

89

WPD – South Wales SSE - Southern

RUOE reductions

Scale adjusted

RUOE reductions

Scale adjusted

RUOE reductions

Scale adjusted

1990/91 – 1991/92 -4.6 -4.3 -0.1 0.4 -5.9 -5.5 1991/92 – 1992/93 -10.5 -10.3 -7.7 -7.6 -4.3 -4.5 1992/93 – 1993/94 4.1 4.8 -4.2 -3.6 4.3 4.9 1993/94 – 1994/95 2.7 3.1 7.1 7.6 -17.0 -16.7 1994/95 – 1995/96 19.3 20.5 -20.1 -19.2 -28.5 -27.8 1995/96 – 1996/97 -40.1 -39.8 -21.6 -21.2 -0.6 -0.2 1996/97 – 1997/98 -6.8 -6.6 3.9 5.0 -14.1 -14.0 1997/98 – 1998/99 6.7 7.4 -23.4 -22.8 0.7 1.7 1998/99 – 1999/00 91.5 91.9 -11.8 -11.1 1999/00 – 2000/01 -45.0 -44.4 -17.9 -17.1 2000/01 – 2001/02 -9.8 -8.9 -20.1 -19.7 -3.5 -2.9 2001/02 – 2002/03 0.0 -0.4 -12.8 -12.1 2.8 3.2 2002/03 – 2003/04 -31.0 -30.6 0.1 0.2 -3.4 -2.6 2003/04 – 2004/05 19.6 20.0 -16.9 -16.6 -8.3 -8.0 Change in RUOE(%) -74.1 -72.6 -71.4 -69.2 -71.7 -69.7 CAGR (90/91-04/05) -9.2 -8.8 -8.6 -8.1 -8.6 -8.2 CAGR (00/01-04/05) -7.1 -6.8 -12.8 -12.4 -3.2 -2.7

SSE – Scottish Hydro

WPD – South Western

Scottish Power CE - Yorkshire

RUOE reduct-ions

Scale adjust-ed

RUOE reduct-ions

Scale adjust-ed

RUOE reduct-ions

Scale adjust-ed

RUOE reduct-ions

Scale adjust-ed

1990/91 – 1991/92 11.7 12.9 1.0 1.4 2.0 2.6 -0.7 -0.4 1991/92 – 1992/93 -2.7 -2.3 3.0 2.7 -16.9 -16.8 0.8 0.7 1992/93 – 1993/94 4.2 4.8 14.8 15.7 9.1 9.7 4.4 5.1 1993/94 – 1994/95 8.8 8.4 -1.4 -1.1 -2.0 -2.1 -16.4 -16.2 1994/95 – 1995/96 -10.6 -10.0 -7.6 -6.6 4.2 4.6 -17.8 -17.2 1995/96 – 1996/97 10.1 10.4 -37.2 -37.0 3.1 3.5 2.1 2.4 1996/97 – 1997/98 0.0 -0.4 -15.8 -15.7 -9.5 -9.8 -14.9 -14.7 1997/98 – 1998/99 50.0 52.4 16.1 17.1 -3.7 -2.9 3.8 4.2 1998/99 – 1999/00 -39.8 -40.2 -8.7 -8.2 12.7 12.8 -4.1 -4.4 1999/00 – 2000/01 -27.6 -26.9 -27.9 -27.2 -31.3 -31.1 -29.0 -28.1 2000/01 – 2001/02 8.5 8.4 -22.9 -22.6 27.4 27.7 -1.9 -1.4 2001/02 – 2002/03 7.6 8.0 -4.5 -3.9 2.0 2.1 -14.2 -14.1 2002/03 – 2003/04 -7.0 -6.8 5.6 6.1 -4.8 -4.7 -13.3 -12.8 2003/04 – 2004/05 6.0 6.3 -1.7 -1.4 -10.4 -10.0 -7.6 -7.2 Change in RUOE(%) -8.6 -4.4 -66.3 -64.1 -27.5 -24.9 -70.2 -68.7 CAGR (90/91-04/05) -0.6 -0.3 -7.5 -7.1 -2.3 -2.0 -8.3 -8.0 CAGR (00/01-04/05) 3.6 3.8 -6.5 -6.1 2.6 2.9 -9.4 -9.0

Note: Output is units of electricity distributed. Source: Ofgem; Company regulatory accounts; Deloitte analysis.

89 We were unable to obtain regulatory accounts for United Utilities for 1999/00 and 2000/01.



5.3.60 Most firms show significant fluctuation in RUOE over time, although a downward trend is generally apparent. Part of the fluctuations can be explained by the significant restructuring that several firms have undergone.

5.3.61 The large RUOE reductions between 1999/2000 and 2000/2001 can be explained by two particular changes taking place in this period:

• during the 1999 distribution price-control review, some costs were reallocated from the electricity distribution business to electricity supply. On average, these reallocations resulted in a reduction of approximately 14% in the companies’ total allowed revenues;

• furthermore, during the same price-control review, Ofgem determined that there was scope for large efficiency gains to be achieved in the industry, and therefore set relatively high targets for some companies. In addition, it did not introduce a rolling Opex mechanism, thus giving companies a strong incentive to make their efficiency savings as soon as possible.

5.3.62 Overall, the CAGRs for RUOE vary considerably between firms, reflecting both differing conditions (e.g. merger costs) and different performances in terms of efficiency achievements. Some of the best performers have managed to more than halve RUOE since privatisation. On average, the results show an annual reduction in adjusted RUOE of 7.2% since privatisation.

5.3.63 These results are very similar to those obtained in the CEPA (2003) report estimating productivity in the DNO’s.

5.3.64 We have also examined the change in RUOE over the last regulatory cycle in particular, as the productivity gains achieved during a full regulatory period are a useful indicator of performance, in that they allow for the periodicity of regulatory incentives to be taken into account. In this period, the annual reduction of adjusted RUOE is, on average, 7.2%.

Northern Ireland Electricity (NIE)

5.3.65 NIE is responsible for the regulated procurement, transmission, distribution and supply of electricity in Northern Ireland. We have, however, taken the figures for distribution and transmission as the most relevant to NG. These have been reported together, as data was not available to separate costs in distribution and transmission.

5.3.66 Since privatisation in 1992, NIE has experience significant output volume growth, with an estimated average annual growth of 2.4%. We have accordingly adjusted our RUOE reduction estimates for the effects of scale, using the same coefficient of elasticity as for the electricity industry in general, 0.721.

5.3.67 Table 5-10 reports the RUOE reduction estimates from 1992/93 to 2004/05:



Table 5-10: Annual RUOE reductions (%) between 1992/93 and 2004/05 - NIE

RUOE reductions RUOE reductions adjusted for scale

1992/93 – 1993/94 -8.4 -7.6 1993/94 – 1994/95 -5.2 -4.7 1994/95 – 1995/96 -17.2 -16.6 1995/96 – 1996/97 49.0 50.1 1996/97 – 1997/98 -39.4 -39.1 1997/98 – 1998/99 11.3 12.4 1998/99 – 1999/00 -14.8 -14.3 1999/00 – 2000/01 -5.0 -4.4 2000/01 – 2001/02 -8.6 -8.5 2001/02 – 2002/03 5.8 6.5 2002/03 – 2003/04 -23.5 -23.2 2003/04 – 2004/05 -8.3 -8.8 Change in RUOE(%) -60.3 -57.7 CAGR (1991/92 – 2004/05) -7.4 -6.9 CAGR (2000/01 – 2004/05) -9.2 -8.9 CAGR (1996/97 – 2001/02) -15.9 -15.4 CAGR (2002/03 – 2004/05) -16.2 -16.0

Note: Output is units of electricity sent out from the power station, i.e. transmitted and distributed. Source: NIE; Deloitte analysis.

5.3.68 The annual adjusted RUOE reduction estimate for the whole period examined was

6.9%, consistent with what was observed in electricity distribution.

5.3.69 When considering the RUOE change for the period corresponding to NG’s last full regulatory cycle, 2000/01-2004/05, the RUOE reduction estimate is 8.9%. However, as NIE was privatised in 1002, two years after the privatisation of the electricity industry in England and Wales, NIE’s regulatory cycle is out of line with that of its counterparts in Great Britain. The RUOE reduction estimate for NIE’s last full regulatory cycle (1996/97 – 2001/02) is quite markedly higher, at 15.4%, similar to the estimate of 16% for the incomplete regulatory cycle from 2002/03 to 2004/05.

Scottish electricity transmission companies

5.3.70 Privatisation of the transmission industry in Scotland occurred in 1990/1. However, the transmission businesses of SPT and SHETL did not exist as separate legal entities until October 2001, resulting in slightly inconsistent regulatory processes. To adjust for this, we added back to Opex a cross subsidy from Scottish Hydro generation to transmission for the years 1990/91 to1994/95.

5.3.71 Figures have been adjusted for scale, again using a scale elasticity coefficient of 0.721.



Table 5-11: Annual RUOE reductions (%) between 1990/91 and 2004/05 - SPT


for scale 1990/91 – 1991/92 17.6 17.5 1991/92 – 1992/93 35.6 35.6 1992/93 – 1993/94 -5.6 -5.1 1993/94 – 1994/95 -14.5 -10.9 1994/95 – 1995/96 -18.5 -16.9 1995/96 – 1996/97 -6.8 -6.1 1996/97 – 1997/98 2.7 1.7 1997/98 – 1998/99 -9.1 -6.7 1998/99 – 1999/00 -3.8 -3.7 1999/00 – 2000/01 -2.2 -4.4 2000/01 – 2001/02 1.9 2.7 2001/02 – 2002/03 -11.9 -11.5 2002/03 – 2003/04 14.3 13.1 2003/04 – 2004/05 3.2 3.2 Change in RUOE(%) -9.2 -2.8 CAGR (1990/91 – 2004/05) -0.7 -0.2

Note: Output is units of electricity transmitted through the system. Source: SPT regulatory accounts; data provided to Ofgem by SPT in price control returns. Deloitte analysis.

Table 5-12: Annual RUOE reductions (%) between 1990/91 and 2004/05 - SHETL


for scale 1990/91 – 1991/92 17.0 18.1 1991/92 – 1992/93 -19.7 -19.2 1992/93 – 1993/94 11.2 12.6 1993/94 – 1994/95 -26.0 -21.9 1994/95 – 1995/96 4.6 6.4 1995/96 – 1996/97 -3.7 -4.4 1996/97 – 1997/98 8.3 9.1 1997/98 – 1998/99 28.0 29.5 1998/99 – 1999/00 -21.4 -20.4 1999/00 – 2000/01 -18.1 -19.0 2000/01 – 2001/02 23.1 21.5 2001/02 – 2002/03 -0.9 -1.0 2002/03 – 2003/04 -4.4 -4.2 2003/04 – 2004/05 3.3 3.3 Change in RUOE(%) -16.3 -8.4 CAGR (1990/91 – 2004/05) -1.3 -0.6

Note: Output is units of electricity transmitted through the system. Source: SHETL regulatory accounts; data provided to Ofgem by SHETL in price control returns. Deloitte analysis.



5.3.72 Table 5-11 and Table 5-12 show that both SHETL and SPT have experienced slight

decreases in RUOE over the period examined, with the annual adjusted RUOE decreases being 10.2% and 0.6% for SPT and SHETL respectively.

5.3.73 These figures may be slightly misleading in the case of SHETL, as the relatively high RUOE value in 2004/05 is due to a large drop in output transmitted in that year, rather than any cost increases.


5.3.74 In England and Wales, NGET has run the national transmission system since the privatisation of the electricity industry in 1990. Prior to privatisation, electricity generation and transmission were managed by the Central Electricity Generating Board (CEGB).

5.3.75 To calculate RUOE, data has been taken from the company’s regulatory accounts.

5.3.76 Certain adjustments have been made for the purposes of consistency:

• following the introduction of the New Electricity Trading Arrangements in 2001/2002, the ancillary services business ceased to be a separate business under the Transmission Licence and those activities were then reported within the transmission business. We have therefore included ancillary services costs in transmission operating costs prior to 2001/2002;

• from 1997/98 onwards, operating costs in the regulatory accounts include the costs of the Transmission services Incentive Scheme, which was previously the responsibility of the Electricity Pool of England and Wales. As these costs are essentially associated with incentive schemes for undertaking system operation roles, they are of a different nature to the network ownership and operation business, and so we have removed them from our analysis90; and

• in 2001/2002, purchases of electricity were grouped with the Transmission Services Incentive Scheme and renamed the Balancing Services Incentive Scheme. As we have been removing the costs of the Transmission services Incentive Scheme, we also remove the Balancing Services Incentive Scheme costs. This further requires the removal of purchases of electricity costs for all years.

5.3.77 In 1999/2000, there was a move from historic-cost accounting (HCA) to current-cost accounting (CCA) in the preparation of companies’ regulatory accounts. Similar to electricity distribution, this has only affected the depreciation component of operating costs, and so does not impact on our analysis.

5.3.78 From 1990/91 to 2004/05, NGET experienced increasing output volumes, with average annual growth in TWh transmitted being approximately 1.2%. We have therefore also adjusted our RUOE estimates for economies of scale, using the same scale elasticity estimate as for the distribution companies.

90 This is consistent with what has been done in by Europe Economics (2003) and Oxera (2003).



5.3.79 Table 5-13 below reports the RUOE reductions from 1990/91 to 2004/05.

Table 5-13: Annual RUOE reductions (%) between 1990/91 and 2004/05 - NGET


for scale 1990/91 – 1991/92 15.7 15.8 1991/92 – 1992/93 -7.9 -8.0 1992/93 – 1993/94 -14.0 -13.7 1993/94 – 1994/95 -13.3 -13.0 1994/95 – 1995/96 -8.2 -7.3 1995/96 – 1996/97 -5.7 -5.5 1996/97 – 1997/98 -10.3 -10.1 1997/98 – 1998/99 -8.8 -8.4 1998/99 – 1999/00 6.0 6.2 1999/00 – 2000/01 -5.6 -4.8 2000/01 – 2001/02 1.0 0.4 2001/02 – 2002/03 -9.9 -9.6 2002/03 – 2003/04 -5.3 -4.8 2003/04 – 2004/05 -7.0 -6.8 Change in RUOE(%) -54.8 -53.1 CAGR 1990/91 – 2004/05 -5.5 -5.3 CAGR 2000/01 – 2004/05 -5.4 -5.3 CAGR 1995/96 – 2000/01 -5.0 -4.7 CAGR 1990/91 – 1995/96 -6.1 -5.8

Note: Opex is less Transmission/Balancing Services Incentive System charges. Output is units of electricity transmitted. Source: NGET regulatory accounts; NG. Deloitte analysis.

5.3.80 Electricity transmission has shown a marked increase in operating cost efficiency, with

an annual decrease in adjusted RUOE of 5.3% since privatisation. The main exception to this downward trend is the adjusted RUOE increase of 15.8% between 1990/01 and 1991/2. In this first year after privatisation, significant restructuring costs relating to NGET’s new commercial/charging functions and the implementation of financial and administrative systems and control were incurred, resulting in the increase.

5.3.81 The CAGR in RUOE achieved by NGET during the latest full regulatory period, adjusted for scale, is again a decrease of 5.3%. This is similar to the reductions in the first and second regulatory period of 5.4% and 4.6% respectively, showing NGET has made relatively constant cost reductions over each regulatory period since privatisation.

NGG

5.3.82 Since privatisation in 1986, when British Gas plc was formed, there has been intense restructuring activity and multiple changes to the function of NGG (initially British Gas, then Transco, then NG). For this reason, robust time series data for NGG is not available. In fact, most studies examining RUOE reductions in privatised network utilities in the UK have not included the gas industry, due to the unreliability of the data. Our RUOE estimates, therefore, must be treated with caution.

5.3.83 In 1996, separate price controls were established for the supply and transportation units of British Gas. Due to inconsistencies between regulatory accounts before and after this, we have only looked at operating costs trends from 1996 onwards.

5.3.84 The regulatory accounts do not contain a split between gas transmission and distribution services, being grouped together as transportation. Before 2001/2, moreover, transportation services also included meter and meter reading services.



5.3.85 We have stripped out both metering services from transportation, using the relative proportions of metering to transportation services after 2001/2. However, we are unable to remove distribution from transportation.

5.3.86 We have therefore also examined the Transco plc statutory accounts, which separate out transmission from 2000 onwards.

5.3.87 Other points to note are:

• the accounting basis changed from modified historical cost to historical cost in 2001/02 - this has been adjusted for;

• the financial year changed from a calendar year in 2000 to a financial year ending in March in 2001/02. This has been adjusted for in the accounts in the case of transmission, but not for transportation; and

• NG has only been able to provide output data on a calendar year basis, so where financial years are not on a calendar year basis we have used output data for the year making up March to December of the financial year. (e.g. 2002 output data has been used for the financial year 2002/3).

5.3.88 As an industry which is likely to experience economies of scale, having a reliable estimate of the coefficient of scale elasticity is also clearly important. This is of particular relevance as output transmitted through the network has increased by 30% since 1996, and demand composition has changed, with more demand from the power sector, the supply of which requires larger pipelines. However, there has been little assessment of elasticity coefficients done for gas infrastructure. Europe Economics (2001) investigated RUOE reduction for Transco, but did not take scale effects into account.

5.3.89 Ideally, detailed econometric analysis of panel data, or alternatively expert engineering analysis should be used to assess the extent to which productivity growth can be attributed to exploitation of scale economies. In the absence of adequate data or time, we have used the same assumption for gas as was used for electricity; that is, a scale elasticity coefficient of 0.721.

Table 5-14: Annual RUOE reductions (%) between 1996 and 2004/05 – NGG

RUOE reductions RUOE reductions adjusted for

scale Transportation Transmission Transportation Transmission

1996 – 1997 -30.4 -29.0 1997 – 1998 -20.0 -19.0 1998 – 1999 -11.4 -8.4 1999 – 2000 -4.4 -2.1 2000 – 2001/02 8.1 14.4 14.7 14.4 2001/02 – 2002/03 3.9 -8.0 -2.0 -7.1 2002/03 – 2003/04 -15.3 -9.9 -15.0 -9.5 2003/04 – 2004/05 17.4 6.3 16.3 5.3 Change in RUOE entire period -47.3 0.8 -42.6 1.3 CAGR (1996 - 2004/05) -7.7 -6.7 CAGR (2000 - 2004/05) 2.8 0.2 2.9 0.3

Note: Output data is NTS throughput by calendar year. Source: Transco plc annual reports; output data from NG. Deloitte analysis.

5.3.90 Table 5-14 shows that gas transportation has realised large efficiency gains over the

past ten years. Since 1996, RUOE has reduced by an estimated 6.7% annually, when adjusted for scale.



5.3.91 However, most of the large efficiency gains seem to have occurred in the 1990’s. In the past five years, transportation has seen RUOE increases of 2.9% annually, again scale adjusted. Estimated RUOE changes for transmission show a similar outcome: over the past five years, RUOE has increased by a scale-adjusted 0.3% annually. RUOE has, however, increased less annually for transmission than for transportation.

Summary

5.3.92 Table 5-15 contains for each company or industry the following information:

• the period examined (generally the period since privatisation, unless data was not available or comparable);

• the compounded annual growth rate (CAGR) in RUOE over the same period; and

• the CAGR in RUOE adjusted for scale.

5.3.93 Figure 5-7 presents graphically the information in Table 5-15.

Table 5-15: Summary of RUOE reductions

Period CAGR (%) Scale Adjusted

CAGR (%) Railtrack (track route) 1994/95 – 2004/05 3.8 3.8 Railtrack (passenger km) 1994/95 – 2004/05 -0.4 -0.1 BT (call volume) 1997/98 – 2003/04 -8.2 -7.5 BT (composite measure) 1997/98 – 2003/04 -5.8 -5.2 Water 1997/98 – 2004/05 -2.2 Sewerage 1997/98 – 2004/05 -0.7 SPT 1990/91 – 2004/05 -0.7 -0.2 SHETL 1990/91 – 2004/05 -1.3 -0.6 Electricity Distribution 1990/91 – 2004/05 -7.6 -7.2 NIE 1992/93 – 2004/05 -7.4 -6.9 Gas Transportation 1996 – 2004/05 -7.7 -6.7 NGG 2000 – 2004/05 0.2 0.3 NGET 1990/91 – 2004/05 -5.5 -5.3

Source: Various data sources - see tables above for each industry/company; Deloitte analysis.



Figure 5-7: Scale adjusted CAGR in RUOE

-10.0

-8.0

-6.0

-4.0

-2.0

0.0

2.0

4.0

6.0

CAGR (%)

BT1

Electricity distribution

BT2

Rail1

Rail2

NGET

SPT

Water

Sewerage

NGGtransmission

NGGtransportation

SHETL

NIE

Rail1: track route BT1 : call volume

Rail2: passenger km BT2: composite measure

Note: CAGR figures are over the entire period analysed for each industry/ company. Source: Data sources vary: see individual discussions above for each industry/ company. Deloitte analysis.

5.3.94 It can be seen from Table 5-15 and Figure 5-7 that compound annual changes in

RUOE have varied quite substantially between the different companies and industries, although most comparators have experienced reductions in RUOE.

5.3.95 NGET compares relatively favourably with other privatised industries, with its annual cost reductions exceeding those of seven of its comparators. However, BT, NIE, gas transportation and aggregated electricity distribution have all seen greater cost reductions than NGET, each surpassing NGET’s annual CAGR in RUOE by at least 1.4%.

5.3.96 The findings for gas are more ambiguous. Gas transportation has experienced significant reductions in RUOE since 1996. However, the lack of robust data for transportation, due to the large amount of restructuring experienced by BG/Transco/NG, means that these figures cannot be entirely relied upon.

5.3.97 For transmission alone, NGG’s performance is poor compared to that of other privatised industries and gas transportation. This may partly be due to the short time period examined; however, NGET and the electricity distribution industry achieved scale-adjusted annual reductions in RUOE of 5.3% and 7.2% respectively, in comparison to NGG’s annual RUOE increase of 0.3%, when viewed over roughly the same period.

5.3.98 NGET is probably most accurately compared with the electricity distribution companies. We have examined the weighted RUOE change for the aggregated electricity distribution industry, which is defined as the annual percentage difference of the aggregate industry wide RUOE (in turn, defined as the sum of costs divided by the sum of outputs in a single year.)

5.3.99 Table 5-16 shows the annual RUOE reductions for electricity distribution.



Table 5-16: Annual RUOE reductions (%) between 1990/91 and 2004/05 – electricity distribution


for scale 1990/91 – 1991/92 -3.4 -2.9 1991/92 – 1992/93 -3.7 -3.8 1992/93 – 1993/94 3.0 3.5 1993/94 – 1994/95 -3.9 -3.7 1994/95 – 1995/96 -9.9 -9.0 1995/96 – 1996/97 -15.0 -14.6 1996/97 – 1997/98 -8.6 -8.5 1997/98 – 1998/99 -1.5 -0.7 1998/99 – 1999/00 -2.1 -1.8 1999/00 – 2000/01 -27.1 -26.4 2000/01 – 2001/02 -12.7 -12.3 2001/02 – 2002/03 -2.4 -2.0 2002/03 – 2003/04 -5.2 -4.8 2003/04 – 2004/05 -9.8 -9.5 Change in RUOE(%) -66.9 -64.9 CAGR 90/91 – 04/05 -7.6 -7.2

Note: Weighted RUOE reductions across all distribution companies. Output is units of electricity transmitted. Source: Company regulatory accounts; Ofgem. Deloitte analysis.

5.3.100 There is a substantial decline in adjusted RUOE of almost 30% between 1999/00 and

2000/1, the beginning of the present price control period. Reasons for this were discussed in 5.3.61. In particular, a part of this decline was a result of the change in the treatment of metering activities, which removed revenues of around £100m. However, there were further adjustments to distribution operating costs arising from revised allocation of costs between distribution and supply. In total, these amounted to around £275m.

5.3.101 CEPA (2003), when examining productivity improvements in the DNO’s, decided after consultation with the DNO’s only to adjust for the reallocation of metering activities. Further adjustments were not made due to counter-cost movements resulting from mergers, price controls, capitalisation etc. This still leaves exceptional performance in 2000/01, so we have additionally reported analysis which adjusts for the total reallocation.

5.3.102 Table 5-17 compares NGET’s performance over each of three price control periods with that of electricity distribution, as well as over the total period since privatisation and over the past ten years. Figures are shown for unadjusted electricity distribution, as well as distribution adjusted for metering activities and for total reallocations.

Table 5-17: Scale-adjusted CAGR in RUOE (%) for aggregated electricity distribution and NGET NGET Electricity

distribution Electricity distribution with metering adjustments

Electricity distribution with all

adjustments CAGR (1990/91 - 2004/05) -5.3 -7.2 -6.9 -6.2

CAGR (2000/01 - 2004/05) -5.3 -7.2 -7.2 -7.2

CAGR (1995/96 - 2000/01) -4.7 -10.9 -9.9 -8.1

CAGR (1990/91 - 1995/96) -5.8 -3.3 -3.3 -3.3

CAGR (1994/95 - 2004/05) -5.2 -9.3 -8.8 -7.8 Source: Deloitte analysis.



5.3.103 Table 5-17 shows that since privatisation, the electricity distribution companies have experienced, on aggregate, greater annual reductions than NGET in scale-adjusted RUOE. The difference is most marked for unadjusted distribution, where the scale-adjusted CAGR in RUOE is 7.2%, almost two percentage points greater than NGET. However, even when adjusted for all reallocations, the annual performance of distribution is still almost a percentage point better than that of NGET.

5.3.104 Similar results are seen over the past ten years. In fact, scale-adjusted annual reductions in RUOE for unadjusted distribution are almost a full four percentage points higher than those of NGET, and more than two percentage points higher when adjusted for all reallocations.

5.3.105 In the last price control period, NGET again shows smaller annual reductions in RUOE than does distribution, with 5.3% as compared to the 7.2% exhibited by distribution.

5.3.106 The difference in annual cost reductions between NGET and the distribution companies gives rise to potential savings on the part of NGET. When considering cost reductions over the past ten years, had NG reduced operating costs at the same rate as the distribution business it would now have costs approximately £68 million lower (in the case where distribution was adjusted for all reallocations. For unadjusted distribution and distribution adjusted for metering reallocations, potential savings are around £103m and £93m respectively.) These potential savings are summarised in the table below:

Table 5-18: Potential savings on operating costs for NGET if RUOE reductions had been the same as electricity distribution

Electricity distribution

Electricity distribution with metering adjustments

Electricity distribution with all

adjustments

Potential savings (£’m) 103.0 93.2 68.7

Source: Deloitte analysis.



5.4 Comparisons with International Transmission Companies

5.4.1 In the next section we compare the performance of NG with that of international

transmission companies.

5.4.2 The international comparisons of transmission companies are limited by several factors. Detailed, disaggregated data is frequently not available especially for European companies. Moreover, data may not be separated between transmission and distribution.

5.4.3 Furthermore, there is often an inconsistent basis for data. In many cases data is not available in sufficient detail to allow adjustments for these differences. Examples of potential sources of inconsistency include the following.

• Costs may be classified differently in different jurisdictions, for example between operating and capital costs.

• Accounting basis for the financial statements may differ between the different European countries, so recorded costs and turnover may reflect different measures.

• There may be wide differences in uncontrollable, such as rates.

• There may be different inclusion of transmission owner and system’s operator costs.

• There may also be differences in the voltage levels included in the transmission lines at different voltages.

• Information on peak load on the system is not weather-adjusted, and so reflects the severity of winter temperatures in a particular year.

5.4.4 Finally, there are large differences in operating environment and history between different companies. Grids have developed serving different demands and with different histories of ownership, regulation and policy objectives. This leads to inevitable differences in unit costs. In particular, NGET is an unusually large and dense transmission network, driven by the size and density of population in England. This is particularly relevant in the case where the calculation of unit costs is based on kilometres of high voltage line.

5.4.5 To illustrate this point, the following figures compare the operating conditions faced by NGET and various comparator European electricity transmission companies. Figure 5-8 shows the population densities in England and Wales (where NGET operates) and in the comparator European countries, revealing NGET’s operating area to be far more densely populated than that of its comparators. The population per square kilometre in England and Wales is almost three times greater than that of Portugal and France, the next most densely populated countries in the sample.

5.4.6 Figure 5-9 shows the relationship between peak load on the system and kilometres of high voltage line for NGET and comparator European companies. Again, NGET is an outlier in the sample, being relatively small in terms of network length but with a large power demand on the system.



Figure 5-8: Population densities in comparator European companies

0

50

100

150

200

250

300

350

400

England

+Wales

Portugal France Spain Sweden

People per sq. km

Source: The CIA World Factbook, www.cia.gov/cia/publications/factbook/geos/us.html

Figure 5-9: Operating environments of NGET and European comparators in 2004

0

20000

40000

60000

80000

100000

120000

0 10000 20000 30000 40000 50000 60000 70000 80000 90000

Peak load on system in 2004

Km of high voltage line in 2004 RTE (France)

NGET

Terna (Italy)

Red Electrica (Spain)

Svenska

Kraftnät

(Sweden)

Statnett (Norway)

REN (Portugal)

Tennet (NL)

Source: Company regulatory accounts and websites.

5.4.7 Ofgem has attempted in the past to carry out more detailed benchmarking studies.

These have yielded insights with limited robustness. In the light of this we have not attempted to apply more sophisticated econometric or statistical methods such as DEA or SFA within the scope of this work.

5.4.8 The difficulties of making international comparisons mean that they are unlikely to yield firm conclusions. Instead they are most likely to give general indications of how NG compares to other companies, and in particular if there is any evidence of unusually high or low efficiency.



International comparisons with electricity companies

5.4.9 In the case of electricity transmission, comparisons are made using European and US electricity transmission companies.

5.4.10 We have used kilometres of high voltage line and peak load recorded on the system as cost drivers.

5.4.11 As a transmission system is designed for a forecast peak load, this is a reasonably good indicator of volume and thereby cost. However, as discussed before, peak load also reflects the severity of weather conditions in a year, so may be misleading as a cost driver. It is also affected by economic cycles and may have a poor relationship with the activity of transmission companies which is essentially asset driven.

5.4.12 Using kilometres of line as a cost driver also has significant drawbacks in that this measure does not differentiate lines at different high voltages, as well as not fully reflecting the density of a network.

5.4.13 We therefore do not depend on one definition of the appropriate driver but have tested several.

5.4.14 We considered using circuit ends as an additional cost driver. However, NGC noted during the last price control review that the number of circuit ends is poorly correlated with maintenance costs associated with overhead lines. Furthermore, data on circuit ends (or even circuit breakers as a proxy for circuit ends) is not readily available for the European comparator companies. We therefore decided against circuit ends as a cost driver.

Comparisons with European electricity transmission companies

5.4.15 We have compared NGET’s efficiency to that of companies in other European countries. We have selected companies which have transmission companies that are ‘stand alone’ or can be separately identified. The companies are shown in the table below.

Table 5-19: European transmission comparator companies

Company Country of operation

Terna91 Italy

Tennet Netherlands

Svenska Kraftnät Sweden

Statnett Norway

Réseau de Transport d'Electricité (RTE) France

Rede Eléctrica Nacional (REN) Portugal

Red Electrica de España (Red Electrica) Spain Source: company websites

5.4.16 We have compared NG with the European transmission companies using the following simple benchmarking ratios:

• Operating costs/turnover

• Personnel costs/turnover

• Operating costs/km high voltage line

• Personnel costs/km high voltage line

91 Terna also has operations in Brazil, and it is not clear whether the financial statements include

information from these subsidiaries.



• Operating costs/peak load on system lines92

• Personnel costs/peak load on system lines

5.4.17 Information used to derive these ratios is taken from the companies’ financial statements and from data on structural assets provided on the companies’ websites. NGET reports data on both double and single circuit lengths. As the basis of reporting for the European companies is not clear, we have run the analysis with both double and single values for NGET.

5.4.18 Although our focus is on the controllable operating costs of NGET, information on controllable costs is not readily available for the other companies used for comparison. Our calculation of unit operating costs therefore uses total operating costs excluding depreciation costs.93

5.4.19 It is unclear whether Transmission/Balancing Services Incentive Scheme (BSIS) costs should be included in NGET’s operating costs in a comparison with European companies. These costs are associated with incentive schemes for undertaking system operation roles. We have therefore run the analysis with and without these costs, denoting operating costs without the BSIS costs as “adjusted”94.

5.4.20 Data has been left in nominal form, with UK data converted to Euros at a constant exchange rate, at the average of the 2004 and 2005 inter-bank exchange rates.

5.4.21 The charts show each of these six benchmarking ratios.

92 This is the peak recorded demand on the electricity transmission network during the course of the

financial year. 93 Operating costs for NGET are taken from NGC and NG’s regulatory accounts and include both

transmission and interconnector costs. 94 Furthermore, in 2001/2002, purchases of electricity were grouped with the Transmission Services

Incentive Scheme and renamed the Balancing Services Incentive Scheme in 2001/02. The removal of the Balancing Services Incentive Scheme costs further requires the removal of purchases of electricity costs for all years.



Figure 5-10: Operating costs (less depreciation)/turnover

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

1998 1999 2000 2001 2002 2003 2004

Year End*

Euros (nominal)

Terna

Tennet

Svenska Kraftnät

Statnett

RTE

REN

Red Electrica

NG

NG (adjusted)

*The financial year of the European companies ends 31 December. For the purposes of this comparative exercise, National Grid’s financial year has been adjusted to fit this. For example, the financial year 2004/05 is recorded under 2004. Source: Company reports and accounts; NG regulatory accounts. Deloitte analysis.

Figure 5-11: Personnel costs/turnover

0.00

0.05

0.10

0.15

0.20

0.25

1998 1999 2000 2001 2002 2003 2004

Year End

Euros (nominal)

Terna

Tennet

Svenska Kraftnät

Statnett

RTE

REN

Red Electrica

NG

Source: Company reports and accounts; NG regulatory accounts. Deloitte analysis.



Figure 5-12: Operating costs (less depreciation)/peak load on system

0

5000

10000

15000

20000

25000

30000

35000

1998 1999 2000 2001 2002 2003 2004

Year End

Euros/M

W (nominal)

Terna

Tennet

Svenska Kraftnät

Statnett

RTE

Red Electrica

NG

NG (adjusted)

Source: Company reports and accounts; NG regulatory accounts. Peak load data from company websites. Deloitte analysis.

Figure 5-13: Personnel costs/ peak load on system

0

1000

2000

3000

4000

5000

6000

7000

8000

1998 1999 2000 2001 2002 2003 2004

Year End

Euros/M

W (nominal) Terna

Tennet

Svenska Kraftnät

Statnett

RTE

REN

Red Electrica

NG




Figure 5-14: Operating costs (less depreciation)/km high voltage lines

7000

27000

47000

67000

87000

107000

127000

147000

1998 1999 2000 2001 2002 2003 2004

Year End

Euros/Km (nominal)

Terna

Tennet

Svenska Kraftnät

Statnett

RTE

Red Electrica

NG(double circuit)

NG (total circuit km)

NG (adjusted, double circuit)

NG (adjusted, total circuit km)


Figure 5-15: Personnel costs/km high voltage lines

0

5000

10000

15000

20000

1998 1999 2000 2001 2002 2003 2004

Year End

Euros/km (nominal)

Terna

Tennet

Svenska Kraftnät

Statnett

RTE

REN

Red Electrica

NG (double circuit)

NG (total circuit km)




5.4.22 The charts show NGET to have a lower proportion of operating costs to turnover than most European operators95. Indeed, when considered without BSIS costs, NGET’s unit costs in this respect are the lowest out of all comparator companies.

5.4.23 NGET’s costs per kilometre of double circuit high voltage line are substantially higher than those of the European operators, with operating costs (less BSIS costs) and personnel costs per kilometre of high voltage line being approximately 53% and 311% higher than the European average, respectively. This large cost gap is reduced when NGET’s costs are measured per kilometre of total circuit length, but NGET still appears to have higher unit costs than most other operators. The cost gap could in large part reflect the density of NGET’s grid.

5.4.24 NGET’s costs are more in line with those of other operators’ costs if measured per peak GWh on the transmission system. This is shown in Figure 5-12 and Figure 5-13, where NGET’s unit costs are in the middle to lower range of comparators’ unit costs.

Growth rates in unit costs

5.4.25 Table 5-20 below shows the compound annual rate of growth of the ratio of operating and personnel costs to kilometres of high voltage line. This cost driver is chosen due to its relative constancy over the period in question.

Table 5-20: Compound annual growth rates in nominal unit costs from 2000-2004

Total operating costs (less depreciation)/km high

voltage line

Personnel costs/km high voltage lines

Statnett 15.4% 5.5% Svenska Kraftnät 8.9% 8.4% REN 2.9% -1.4% Tennet 2.9% 9.4% NG -2.1% -2.1% RTE 2.1% 4.4% Terna -1.8% -2.1% Red Electrica -2.3% -4.5%


5.4.26 Unlike most European operators, NGET’s unit operating and personnel costs have

decreased slightly over the period.

95 This could imply they have a higher proportion of capital costs to turnover, or that capital and operating

costs have different definitions to that used in Europe.



Comparison with US electricity transmission companies

5.4.27 Further to the above analysis, we have also compared NGET’s efficiency to that of companies in the US. Again, we have selected companies which have transmission companies that are ‘stand alone’ or can be separately identified. The companies were also chosen due to their relatively large size, making them comparable to NGET.

5.4.28 The companies are shown in Table 5-21 below, with a brief description of each.

Table 5-21: US transmission comparator companies

Company Description

PPL Electric Utilities Corp.

transmits and distributes electricity to retail customers in eastern and central Pennsylvania.

Commonwealth Edison Co.

Transmits and distributes electricity in Chicago and surrounding areas of Northern Illinois.

Consolidated Edison Co. of New York Inc.

controls the transmission and distribution network in New York.

Florida Power & Light Co.

generates, transmits, distributes and sells electric energy in the southern portion and eastern seaboard of Florida.

Northern States Power Co.

generates, transmits and distributes electricity in north-western Wisconsin and in the western portion of the Upper Peninsula of Michigan.

PSI Energy, Inc. transmits and distributes electricity to 69 of Indiana's 92 counties.

Source: Company websites

5.4.29 Detailed quantitative information is available for U.S. investor-owned utilities in the form

of annual data provided to the Federal Energy Regulatory Commission (FERC)96. We have examined this data for the companies listed above from 1996 to 200497.

5.4.30 Data for NGET comes from the company’s regulatory accounts.

5.4.31 In order to compare NGET with the US companies, we have derived unit costs on the basis of yearly peak demand98. Due to data limitations, we have used miles of high voltage line in 2004 as a constant figure for the period of our analysis, but peak demand varies year on year over the period. Again, we have reported the results of the analysis for NGET for both single and double circuit mileage, as well as for costs with and without BSIS costs. (See paragraph 5.4.19)

5.4.32 Specifically, the ratios we have examined are:

• Opex/km high voltage line

• Personnel costs/km high voltage line

• Opex/peak load on system lines

• Personnel costs/peak load on system lines

96 Each year major investor-owned utilities are legally obliged to complete a FERC ‘Form 1’ consistent

with the Uniform System of Accounts prescribed for public utilities and licensees subject to the provisions of the Federal Power Act (1935). The form is a comprehensive financial and operating report submitted for Electric Rate regulation and financial audits. 97 Some data on structural assets is additionally from Platt’s PowerDat database.

98 This is the peak recorded demand from the electricity transmission network during the course of the

financial year as well as miles of high-voltage line (both overhead and underground).



5.4.33 For the US companies, OPEX used is transmission operating and maintenance costs less depreciation. For NGET, we have used operating costs less depreciation for the transmission and interconnectors businesses, as recorded in the regulatory accounts99. Data is left in nominal form, with UK data converted to US dollars according to the prevailing rate on 31 March 2005.

5.4.34 The figures below show each of these four benchmarking ratios:

Figure 5-16: Opex/peak load on system lines

0

5

10

15

20

25

30

1996 1997 1998 1999 2000 2001 2002 2003 2004

Year End*

US $'000/M

W (nominal)

PPL

Commonwealth Edison

Consolidated Edison

Florida

Northern States

PSI

NG

NG (adjusted)

* US data is on a calendar year basis, while the UK financial year ends 31 March. For the duration of this analysis, we have accordingly compared the UK data with the US data from the previous year; for e.g. UK data from 2002/03 has been compared with US data from 2002. Source: NG regulatory accounts and annual reports; US data from FERC. Deloitte analysis.

99 Prior to 2002/03, we have also included ancillary services. These are later reported within the

transmission business following the introduction of the New Electricity Trading Arrangements in 2002/03. We have also ignored the move from current cost to historic cost accounting in 2001/2, as this only affects the depreciation which we anyway exclude.



Figure 5-17: Personnel Costs /peak load on system lines

0

500

1000

1500

2000

2500

3000

3500

4000

1996 1997 1998 1999 2000 2001 2002 2003 2004

Year End

US $/M

W (nominal)

PPL

Commonwealth Edison

Florida

Northern States

PSI

NG

Source: NG regulatory accounts and annual reports; US data from FERC. Deloitte analysis.

Figure 5-18: Opex/miles high voltage lines

0

50

100

150

200

250

300

1996 1997 1998 1999 2000 2001 2002 2003 2004

Year End

US $'000/m

ile (nominal)

PPL

Commonwealth Edison

Consolidated Edison

Florida

Northern States

PSI

NG(double circuit)

NG (single circuit miles)

NG(adjusted double circuit)

NG (adjusted single circuitmiles)




Figure 5-19: Personnel Costs/miles high voltage lines

0

5

10

15

20

25

30

35

40

45

1996 1997 1998 1999 2000 2001 2002 2003 2004

Year End

US $/m

ile (nominal)

PPL

Commonwealth Edison

Consolidated Edison

Florida

Northern States

PSI

NG (double circuit)

NG (single circuit miles)


5.4.35 Overall, NGET’s unit costs are far higher than those of the comparator US companies.

For Opex (without BSIS costs), the results suggest potential savings on NGET’s transmission Opex of 8% to 82% on the basis of costs per MW peak load on the system, and 74% to 96% on the basis of costs per mile of high voltage line (54% to 95% if considering single circuit miles).

5.4.36 A similar conclusion is reached for personnel costs: the results suggest potential savings on NGET’s personnel costs of 52% to 71% on the basis of costs per MW peak load on the system, and 64% to 96% on the basis of costs per mile of high voltage line (36% to 93% if considering single circuit miles).

5.4.37 Savings of approximately the same magnitude were suggested during the last price control review for NGC:

• 37% - 83% on the basis of costs per transformer, and

• 49% - 87% of the basis of costs per km of overhead line.

5.4.38 Table 5-22 below shows the compound annual rate of growth of the ratio of Opex and personnel costs to miles of high voltage line. This cost driver is chosen due to its constancy over the period in question.

Table 5-22: Compound annual growth rates in nominal unit costs from 1998-2004

Company Opex/miles high voltage line

Personnel costs/miles high voltage lines

PPL -2.6% 18.9% PSI -2.5% 13.7% NG -0.2% 0.7% Consolidated Edison 2.3% 73.1% Florida 3.1% -4.1% Northern States 6.1% -5.5% Commonwealth Edison 33.2% 5.8% Source: NG regulatory accounts and annual reports; US data from FERC. Deloitte analysis.



5.4.39 NGET does not show the largest rate of cost reduction in the sample over the past few years, but still compares favourably compared to most US companies.100

5.4.40 The comparisons are likely to be imperfect since we have not been able to cross-check in detail the consistency of costs in the comparison or allow for different operating environments or reporting conventions. In particular, US companies are likely to have much longer line distances than NGET, allowing them to compare favourably when unit costs are measured on the basis of miles of high voltage line.

5.4.41 We note that the results of this analysis provide general support for the conclusions emerging from our bottom-up analysis. However, we cannot place a high level of reliability on these estimates for the reasons already discussed.

Scottish Transmission Companies

5.4.42 We have further compared NGET with the Scottish transmission companies, SHETL and SPT. These are likely to be better comparators for NGET, due to the common regulatory and accounting environment shared by the three firms. However, it must be noted that NGET’s operating environment differs substantially from that of the Scottish companies, being a far denser grid and on a far larger scale. Also, the capitalisation policy of the three companies differs largely.

5.4.43 We have used the following benchmarking ratios:

• Controllable Opex/km high voltage line

• Controllable Opex/peak load on system lines

5.4.44 Information used to derive these ratios is taken from the HPBQ submission of the three companies and from data on structural assets provided by Ofgem. As before, NGET reports data on both double and single circuit lengths. However, the Scottish companies also report on the same basis, so our analysis uses only single circuit length for kilometres of high voltage line.

5.4.45 The charts show the two benchmarking ratios.

100 The difference between these growth values and those shown against European comparators is due

to the different time periods used.



Figure 5-20: Controllable Opex/peak load on system lines

0

1

1

2

2

3

3

4

4

5

5

2002 2003 2004 2005

Financial Year End

£'000/M

W (nominal)

Scottish Hydro

Scottish Power

NG

Source: Cost data from HBPQ submissions; peak load data from company websites and information provided to Ofgem in HPBQ submissions

Figure 5-21: Controllable Opex/km high voltage line

0

1

2

3

4

5

6

7

8

9

10

2002 2003 2004 2005

Financial Year End

£'000/M

W (nominal)

Scottish Hydro

Scottish Power

NG (single circuit)

Source: Cost data from HBPQ submissions; structural data from company websites and information provided to Ofgem in HPBQ submissions.

5.4.46 As expected, when unit costs are examined in terms of kilometres of high voltage line,

NGET’s unit costs are higher than those of SPT and SHETL due to the differing densities of the networks. On average over the period examined, NGET’s controllable unit costs are 86% and 54% higher than those of SHETL and SPT respectively.



5.4.47 However, NGET compares much more favourably on the basis of peak load on the system, having lower controllable unit costs than both SPT and SHETL. On average, NGET’s controllable unit costs were 50% and 67% lower than SHETL and SPT respectively.

International comparisons with gas companies

5.4.48 No comparison similar to that for NGET is currently possible for gas transmission. This is due to the structure of many of the European gas companies, who are generally large groups whose public accounts do not segment out transmission costs. Attempts to obtain unbundled transmission data from companies or regulators have met with little success, either because it does not exist, or because of confidentiality issues.

5.4.49 However, we have discovered that the Council of European Energy Regulators (CEER) has commissioned a benchmarking study of European gas transmission tariffs. Part of this work includes an efficiency study of TSO costs, currently being carried out by the Electricity Policy Research Group (ERPG) from Cambridge University.

5.4.50 This study aims to develop a simple model for the comparison of the costs of the TSO’s with their output. Attention is being paid to obtaining a consistent cost base on which to compare the TSO’s. ERPG intend to use the detailed cost definitions set out by the Federal Energy Regulatory Commission (FERC) in the US to define what is meant by operating costs and other costs. The European companies participating in the study will then be required to present their costs according to this definition.

5.4.51 As participation in this benchmarking study is voluntary, ERPG do not expect to obtain a large enough sample of European companies to achieve meaningful benchmarks. A group of US companies will therefore be added to the sample.

5.4.52 This is a long term and relatively complex project, employing statistical methods such as DEA and SFA. Persuading European gas companies to participate has also been a complicated and drawn-out procedure.

5.4.53 The report will be available to Ofgem as a member of CEER once it is released in the later half of 2006101.

101 A draft version of the report should be available by mid 2006. Contact Cemil Altin at Ofgem for the

progress of this report.


162

5.5 Conclusions

5.5.1 Based on the analysis in this section we note the following.

Underperformance against the target set in the price control

5.5.2 NGET appears on the basis of the costs it has presented in the HPBQ to have underperformed the targets set by Ofgem in its price control. This is despite the merger, which was not anticipated when the price control was set and is said by NGET to have generated large savings. This implies that there have been small reductions in the level of annual operating costs other than those accounted for by the merger.

5.5.3 NGG outperformed the price control, both in terms of annual cost reductions and overall costs. It is difficult to draw many conclusions from this, due to the alleged over-allocation of costs to the Transmission Owner (offset with the NGG price control by an under-allocation to the distribution business) at the last price control.

Reductions in operating costs have been larger than those in other regulated industries in the UK, yet smaller than those in electricity distribution

5.5.4 The reductions in operating costs for NGET have been larger than those achieved in most other privatised network industries in the UK. However, the electricity distribution industry, as well as some companies such as BT and Northern Ireland Electricity, have achieved greater annual cost reductions.

5.5.5 The most direct comparison for NGET appears to be with electricity distribution companies. In aggregate, these have achieved annual real unit operating expenditure (RUOE) reductions of 6.2% since privatisation and 7.8% in the past ten years, using the most conservative estimate. Using the adjusted operating expenditure suggested by CEPA (2003), these reductions would be 6.9% and 8.8% respectively. This compares with NGET’s annual reduction of 5.3% since privatisation and 5.2% in the past ten years. Although there are some factors specific to electricity transmission, such as the introduction of BETTA, it is not clear that these account for the majority of the difference. Had NG reduced operating costs at the same rate as the distribution business in the last ten years, it would have had costs approximately £68 million lower in 2004/05 by the conservative measure, or approximately £93 million lower with CEPA’s (2003) adjustments.

5.5.6 For gas transmission, small annual increases in operating costs have been experienced in the few years since the unbundling of transportation into transmission and distribution.

No evidence from international comparisons of exceptional efficiency

5.5.7 There is no evidence from international comparators that NGET is exceptionally efficient.

5.5.8 Although NGET has a lower proportion of operating costs to turnover than most European operators, it is in the middle or top of the range of unit costs on the basis of kilometres of high voltage line. Even when unit costs are measured in terms of peak load on the system - where NGET is likely to perform well due to the dense nature of its grid – NGET still does not have the lowest unit costs in the sample, although it is in the middle to lower range of unit costs.

5.5.9 When compared to the US companies, NGET’s unit costs are considerably higher than all others in the sample, for all costs drivers.

5.5.10 However, NGET compares more favourably against the two Scottish transmission companies. As expected, when unit costs are examined in terms of kilometres of high voltage line, NGET’s unit costs are higher than those of SPT and SHETL due to the


163

differing densities of the networks. However, on the basis of peak load on the system, NGET has lower controllable unit costs than both SPT and SHETL.

5.5.11 It has not been possible within the timescale and scope of this exercise to carry out a useful comparison for gas transmission.

5.5.12 Overall, it is not possible to conclude on the basis of this analysis that NGET is materially inefficient. The issues described earlier in this section, especially on data comparability and operating environment, show that there are other factors that may account for NGET appearing less efficient than some of its comparators.


164

Appendix 1: Summary of the provisions analysis provided by National Grid

Table A1-1: NGET provisions analysis for 2004/05 ETO ESO OTHER TOTAL

102

£m £m £m £m

Restructuring / Reorganisation / Mergers 0.0 0.0 (3.0) (3.0)

Pension (7.7) 0.0 (0.0) (7.7)

Tax 0.0 0.0 (820.1)103 (820.1)

Environmental (10.3) 0.0 0.0 (10.3)

Other (6.3) 0.0 (4.6) (10.8)

Provs - at Start of Period (24.3) 0.0 (827.6) (851.9)

Restructuring / Reorganisation / Mergers 0.0 0.0 0.0 0.0

Pension 1.5 0.0 (35.2) (33.7)

Tax 0.0 0.0 (8.3) (8.3)

Environmental 0.0 0.0 0.0 0.0

Other 0.0 0.0 (1.8) (1.8)

Provs - Charged to Profit and Loss 1.5 0.0 (45.3) (43.8)


Pension 0.0 0.0 0.0 0.0

Tax 0.0 0.0 11.1 11.1


Other 0.0 0.0 0.0 0.0

Provs - Released to Profit and Loss 0.5 0.0 11.1 11.6

Restructuring / Reorganisation / Mergers 1.6 0.0 (0.1) 1.5

Pension 0.0 0.0 9.3 9.3

Tax 0.0 0.0 0.0 0.0

Environmental 0.5 0.0 (0.0) 0.5

Other 1.4 0.0 (0.1) 1.2

Provs - Utilisation 3.5 0.0 9.1 12.5


Pension 0.0 0.0 4.9 4.9

Tax 0.0 0.0 1.0 1.0


Other 0.0 0.0 0.0 0.0

Provs - Balance Sheet Reclassification 0.0 0.0 5.9 5.9

Restructuring / Reorganisation / Mergers 1.6 0.0 (3.1) (1.5)

Pension (6.2) 0.0 (21.0) (27.2)

Tax 0.0 0.0 (816.3) (816.3)

Environmental (9.3) 0.0 (0.0) (9.3)

Other (4.9) 0.0 (6.4) (11.4)

Provs - Balance at End of Period (18.8) 0.0 (846.9) (865.7)

Prov - Movement in the Year 5.5 0.0 (19.3) (13.8)

102 The balances in the total column of

Table A1- have been agreed to the NGET statutory financial statements 2004/05 103 The opening tax provision was restated from the prior year closing balance. The restatement reduced

the opening provision by £2.1m. This is in relation to NG’s adoption of FRS20 Accounting for Share Based Payments in 2004/05.


165

Table A1-2: NGG Provisions analysis for 2004/05 GTO GSO OTHER TOTAL

104

£m £m £m £m

Restructuring / Reorganisation / Mergers (2.4) (5.7) (28.3) (36.4)

Pension 0.0 0.0 0.0 0.0

Tax 0.0 0.0 (1,231.0)105 (1,231.0)

Environmental 0.0 0.0 (85.0) (85.0)

Other 0.0 0.0 0.0 0.0

Provs - at Start of Period (2.4) (5.7) (1,344.3) (1,352.4)


Pension 0.0 0.0 0.0 0.0

Tax 0.0 0.0 (34.0) (34.0)

Environmental 0.0 0.0 (9.1) (9.1)

Other 0.0 (4.3) (0.7) (5.0)

Provs - Charged to Profit and Loss (0.9) (5.6) (215.3) (221.8)


Pension 0.0 0.0 0.0 0.0

Tax 0.0 0.0 0.0 0.0

Environmental - Unwinding of Discount 0.0 0.0 (2.0) (2.0)

Other 0.0 0.0 0.0 0.0

Provs - Released to Profit and Loss 0.0 0.0 (2.0) (2.0)


Pension 0.0 0.0 0.0 0.0

Tax 0.0 0.0 0.0 0.0


Other 0.0 0.0 0.0 0.0

Provs - Utilisation 2.2 3.1 120.7 126.0


Pension 0.0 0.0 0.0 0.0

Tax 0.0 0.0 2.0 2.0


Other 0.0 0.0 0.0 0.0

Provs - Transfers 0.0 0.0 2.0 2.0


Pension 0.0 0.0 0.0 0.0

Tax 0.0 0.0 (1,263.0) (1,263.0)

Environmental 0.0 0.0 (89.1) (89.1)

Other 0.0 (4.3) (0.7) (5.0)

Provs - Balance at End of Period (1.1) (8.2) (1,439.0) (1,448.2)

Provs - Movement in the Year 1.3 (2.5) (94.6) (95.8)

104 The balances in the total column of Table A1-2 have been agreed to the NGG statutory financial

statements 2004/05 105 The opening tax provision was restated from the prior year closing balance. The restatement reduced

the opening provision by £4m.


166

Appendix 2: Summary of cash costs analysis

Creditors and accruals

Similarly to provisions; creditors and accruals do not represent cash costs incurred by the business in the period. Accounting costs in relation to creditors and accruals are incurred as soon as the entity has a constructive or legal obligation to pay such costs rather than when the cash payment occurs. If we adopt this strict definition of cash costs, the accounting costs which arise as a result of creditors and accruals and replace these with the cash costs paid in the year in relation to settling these obligations as shown in the following analysis.

Table A2-1 sets out a summary of the creditors and accruals analysis for NGET in 2004/05 provided by NG in tab 1.3.2 of the HBPQ. As noted by NG in appendix 2 paragraph 6 of the HBPQ this analysis was provided for the transmission business as a whole and not split between ETO and ESO as requested by Ofgem. These balances have been agreed to the 2004/05 regulatory accounts of NGET.

Table A2-1: NGET creditors and accruals 2004/05 Opening Closing Movement

£m £m £m

Creditors: amounts falling due within one year:

Trade Creditors 157.8 142.1 (15.7)

Other 230.0 225.8 (4.2)

Total 387.8 367.9 (19.9)

Creditors: amounts falling due after more than one year:

Other creditors 141.8 86.4 (55.4)

Total 141.8 86.4 (55.4)

We requested that NG split out the creditors and accruals balances into ETO and ESO. We also requested that the balances be split between amounts which impact opex and amounts which do not impact opex. Amounts which impact opex are those whose accounting entry is posted to creditors/ accruals and opex. We could then remove the accounting entries posted to opex from ECOC and replace them with the cash costs.

Table A2-2shows the split of creditors and accruals balances between amounts impacting opex and amounts not impacting opex. This analysis was provided by NG. The bottom row of the table shows that the total creditors and accruals impacting opex have decreased by £5.1m during the accounting year 2004/05. This indicates that the required adjustment to remove the creditors and accruals accounting entries and replace them with the cash costs is to increase ECOC by £5.1m

Table A2-2: NGET creditors and accruals 2004/05 showing split between amounts impacting opex and amounts which do not impact opex Opening Closing Movement

£m £m £m

Creditors: amounts falling due within one year:

Impacting opex 136.8 131.7 (5.1)

Not impacting opex 251.0 236.2 (14.8)

Total 387.8 367.9 (19.9)

Creditors: amounts falling due after more than one year:

Impacting opex - - -


Total 141.8 86.4 (55.4)

Total creditors and accruals impacting opex 136.8 131.7 (5.1)


167

Table A2-3 sets out the split of the creditors and accruals balances impacting opex between ETO and ESO as provided by NG. This shows that of the total adjustment to increase to ECOC by £5.1m, £4.5m relates to ETO and £0.6m to ESO.

Table A2-3: Total NGET creditors and accruals impacting opex spit by form of control ETO ESO Total

£m £m £m

Opening 81.8 55.0 136.8

Closing 77.3 54.4 131.7

Movement (4.5) (0.6) (5.1)

The information shown in Table A2-3 for NGET is not available for NGG. This is because no split between the transmission and distribution businesses of the NGG creditors and accruals balances was provided by NG in the HBPQ. There is also no split shown in the regulatory accounts of NGG. This means that none of the creditors and accruals analysis provided by NG for NGG has been agreed to audited information.

Table A2-4 and Table A2-5 provide the same analysis for NGG as shown in Tables 2 and 3 for NGET. This analysis was provided by NG.

Table A2- indicates that in order to adjust creditors and accruals to a cash basis ECOC should be increased by £9.7m for GTO and by £3.6m for GSO.

Table A2-4: NGG creditors and accruals 2004/05 showing split between amounts impacting opex and amounts which do not impact opex Opening Closing Movement

£m £m £m

Creditors: amounts falling due within one year

Impacting opex 90.6 77.3 (13.3)


Total 128.6 108.2 (20.4)

Creditors: amounts falling due after more than one year

Impacting opex - -


Total 137.3 132.3 (5.0)

Total creditors and accruals impacting opex 90.6 77.3 (13.3)

Table A2-5: Total NGG creditors and accruals impacting opex spit by form of control GTO GSO Total

£m £m £m

Opening 59.7 30.9 90.6

Closing 50.0 27.3 77.3

Movement (9.7) (3.6) (13.3)

Prepayments

[Similar analysis to be provided for prepayments. Waiting for the answer to questions DL1119 and DL1120.]


168

Conclusion

Table A2-6 summarises the potential ECOC adjustments resulting from the above analysis of creditors, accruals and prepayments.

Creditor, accruals and prepayments represent short term timing differences on cash costs to the business. As noted in paragraph 4.XX in the main report we would not recommend that these adjustments are made to ECOC.

Table A2-5: ECOC adjustments arising from the review of creditors, accruals and prepayments

ETO £m

ESO £m

GTO £m

GSO £m

Creditors and accruals 4.5 0.6 9.7 3.6 Prepayments Total


169

Deloitte & Touche LLP is a limited liability partnership registered in England and Wales with registered number OC303675 and is

authorised and regulated by the Financial Services Authority.

A list of members’ names is available for inspection at Stonecutter Court, 1 Stonecutter Street, London EC4A 4TR, United

Kingdom, the firm’s principal place of business and registered office.

Tel: +44 (0) 20 7936 3000 Fax: +44 (0) 20 7583 1198.

Deloitte & Touche LLP is the United Kingdom member firm of Deloitte Touche Tohmatsu (‘DTT’), a Swiss Verein whose member

firms are separate and independent legal entities. Neither DTT nor any of its member firms has any liability for each other’s acts

or omissions. Services are provided by member firms or their subsidiaries and not by DTT.

© Deloitte & Touche LLP 2006. All rights reserved.

deloitte draft tpcr report v2 - ofgem · questionnaire under 3 headings - data clarification, cash...

Documents