Operating and Financial Review
Operating Review
Transmission
- UK electricity and gas transmission
- Background information
- Regulation
- Safety
- Operating performance
- Financial performance
- Investment in the networks
- US electricity transmission
Our Transmission business comprises two segments: 'UK electricity and gas transmission' for our UK assets and 'US electricity transmission' for our US assets. Details of each of these segments, including background information on their assets and operations, the regulatory environments in which they operate, their operating and financial performance, and investment in the networks, are set out below.
The results for the Transmission business for the years ended 31 March 2005, 2004 and 2003 were as follows.
Years ended 31 March Transmission | 2005 UK electricity and gas £m | 2005 US electricity £m | 2005 Total £m | 2004 Total (restated) £m | 2003 Total (restated) £m |
|---|---|---|---|---|---|
| Turnover | 1,930 | 283 | 2,213 | 2,185 | 2,300 |
| Operating costs excluding exceptional items and goodwill amortisation | (1,121) | (160) | (1,281) | (1,293) | (1,363) |
| Adjusted operating profit | 809 | 123 | 932 | 892 | 937 |
| Exceptional items | (2) | (3) | (5) | (23) | (50) |
| Goodwill amortisation | - | (18) | (18) | (19) | (21) |
| Operating profit | 807 | 102 | 909 | 850 | 866 |
UK electricity and gas transmission
Background information
Our UK electricity and gas transmission business comprises the ownership and operation of the high-voltage electricity transmission system in England and Wales and of the gas National Transmission System (NTS) in Great Britain. Since 1 April 2005 we have also been responsible for operating the high-voltage electricity transmission system in Scotland.
We own electricity assets which comprise approximately 4,500 miles of overhead line, about 410 miles of underground cable and 341 substations at 243 sites. Day-to-day operation of the electricity transmission system involves the continuous real-time matching of generation output with demand, ensuring the stability and security of the power system and the maintenance of satisfactory voltage and frequency.
The NTS comprises approximately 4,300 miles of high pressure pipe and 25 compressor stations, connecting to eight distribution networks and to third party independent systems for onward transportation of gas to end consumers. Day-to-day operation of the NTS includes balancing supply with demand, maintaining satisfactory system pressures and ensuring gas quality standards are met.
Our UK electricity and gas transmission business has four separately regulated activities:
- electricity transmission owner;
- gas transmission owner;
- electricity system operator; and
- gas system operator.
As electricity transmission owner and gas transmission owner, we own and maintain the physical assets, develop the networks to accommodate new connections and disconnections, and manage a programme of asset replacement and investment to ensure the long-term reliability of the systems.
As electricity system operator and gas system operator, we undertake a range of activities necessary for the successful delivery in real time of secure, reliable and efficient energy and, in the case of electricity, the continuous real-time balancing of supply and demand. The electricity and gas system operator parts of the business are subject to regulatory incentive schemes.
Regulation
Through our subsidiary, National Grid Company plc, we own and operate the electricity transmission assets and are the sole holder of an electricity transmission licence for England and Wales. We have a duty under the Electricity Act 1989 to develop and maintain an efficient, co-ordinated and economical system of electricity transmission and to facilitate competition in the supply and generation of electricity.
Under the terms of the transmission licence, we are responsible for setting charges and maintaining the charging statements, which describe the charges and methodologies used to calculate them. We receive income through charges to generators, distributors, suppliers and directly-connected customers for use of and connection to the transmission system. Transmission Network Use of System charges are levied in respect of the provision of transmission assets and infrastructure (the electricity transmission owner activity) and Balancing Services Use of System charges are levied for operating the system (the electricity system operator activity).
Revenue from charges for using the transmission network and charges for connections made before March 1990 is controlled by a revenue restriction condition set out in the transmission licence. This revenue restriction is known as a price control. The current price control period commenced on 1 April 2001 and was intended to continue until 31 March 2006. However, in order to align electricity and gas transmission price controls, we are currently undergoing a mini review, which will effectively extend the period to 31 March 2007. It is anticipated that this review will address the issue of the increased levels of capital investment that have already been committed in the current price control. We expect these negotiations to conclude by the end of calendar year 2005. We are also preparing for discussions with Ofgem regarding the next five-year price control commencing on 1 April 2007.
Through our subsidiary Transco plc, we own the gas transmission assets, and our operations are undertaken under the terms of the NTS gas transporter licence. We are subject to separate revenue restrictions, known as price controls, in respect of gas transmission owner and gas system operator activities which will both last until 31 March 2007.
With effect from 1 May 2005, our UK gas transmission business and UK Gas Distribution business (and each of the networks which we plan to sell) each hold a gas transporter licence. These licences are derived from the original integrated transmission and distribution licence but have been substantially amended in order to distinguish between the separate activities of transmission and distribution gas transportation, and to facilitate the post sales environment with multiple gas distribution transporters.
Under the terms of the NTS gas transporter licence, we receive income through charges to shippers for entry and exit capacity (gas transmission owner activity) and commodity charges (gas system operator activity). The system entry capacity charges are set via auctions. The exit capacity charges and the entry capacity auction proceeds together recover the allowed revenue under the transmission owner price control in respect of the provision of the transmission assets.
Electricity transmission owner
The electricity transmission owner price control takes into account Ofgem's estimates of operating expenditure, capital expenditure, replacement expenditure and allowed rate of return (which is currently set at a real pre-tax rate of 6.25%) on our regulatory asset value. Our regulatory asset value is currently estimated at around £5.2 billion at 31 March 2005.
The electricity transmission owner is permitted to set charges for connections to the transmission system made since March 1990 to recover the costs directly or indirectly incurred in providing connections, together with a reasonable rate of return.
An amended connection charging methodology for our electricity transmission owner activity, known as 'Plugs', was introduced from 1 April 2004. The changes for Plugs modified the charging boundary between connection assets that were attributable to specific users and the main interconnected transmission network shared by all users. This required us to make repayments to connected parties associated with relevant assets that had been subject to capital contributions or other accelerated payment terms. In total, these repayments were approximately £71 million, of which £61 million has been refunded in 2004/05. The majority of these repayments have been treated as capital expenditure for regulatory purposes.
Gas transmission owner
The gas transmission owner price control takes into account Ofgem's estimates of operating expenditure, capital expenditure, replacement expenditure and allowed rate of return (which is currently set at a real pre-tax rate of 6.25%) on our regulatory asset value. Our regulatory asset value is currently estimated at around £2.5 billion at 31 March 2005.
Electricity system operator
As electricity system operator, we are responsible for the operation of the high-voltage electricity transmission system across England and Wales. With the implementation of the British Electricity Trading and Transmission Arrangements (BETTA), we also took over responsibility for the operation of the transmission system in Scotland on 1 April 2005. Our activities as electricity system operator include the procurement and use of balancing services to match supply and demand continuously. Balancing services include commercial agreements with market participants. These enable the electricity system operator to vary their electricity demand or generation output. Revenue from charges for the provision of balancing services is regulated under an incentive scheme, where benefits of cost savings in system operation compared to a target are shared with customers.
The UK Government's Energy Bill was granted Royal Assent on 22 July 2004. The Act includes the legislative framework for BETTA. The framework provides the transitional and enduring licence obligations required in order to implement BETTA. National Grid Company was formally announced as the Great Britain (GB) System Operator under BETTA on 1 September 2004.
As a result of licence modifications associated with BETTA, we are responsible for operating the GB transmission system, setting charges and maintaining the charging statements for all transmission users in Great Britain. In this role, we recover payments from all GB transmission users and make payments to the Scottish transmission operators in accordance with arrangements set out in the System Operator Transmission Operator Code. Scottish Power is currently seeking judicial review of the Gas and Electricity Markets Authority's decision to approve the GB electricity Transmission Network Use of System charging methodology developed and proposed by National Grid Transco. In addition, under the regulatory arrangements for BETTA the Scottish interconnector (previously outside of the regulated business) now forms part of the regulated businesses of Scottish Power and ourselves.
As GB System Operator, we are also responsible for managing the operations of both the Scottish and the England and Wales networks, and also operating the GB energy balancing mechanism. For 2005/06, the electricity System Operator incentive scheme has been set a target of £377.5 million, with sharing factors for the System Operator external costs of 40% upside and 20% downside, in relation to the operation of the GB transmission system. This compares to a target of £415 million with sharing factors of 40% for upside and downside for 2004/05, which was only in relation to the operation of the England and Wales transmission system. The reduction in target of £37.5 million comparing 2004/05 with 2005/06 is due to the change in treatment of transmission losses, such that the gross value of losses is removed from the target. This is partly offset by the increase in scope of the incentive scheme, from operation of the England and Wales transmission system to the GB transmission system, following BETTA implementation. For comparison with the 2004/05 target, an equivalent target for 2005/06, including the gross value of losses, would be around £500 million.
BETTA has required significant information systems expenditure development during the past year. In particular, this has included a substantial increase in database capacity and the number of displays on our integrated energy management system.
We have recruited approximately 60 staff to support the BETTA activities, in both the commercial area and the control room environment, plus the functions that support it.
In 2004, the energy management system used for electricity system operations was replaced with a new integrated energy management system. The new system not only has the capability to handle the increasing complexity of the England and Wales systems, but also the 30% increase in network size, which was needed to incorporate the Scottish networks, which we now operate. Furthermore, this system is designed to be upgraded on an ongoing basis and we believe it will be adequate for future growth of the electricity network.
Gas system operator
The gas system operator price control includes incentive arrangements such that if performance exceeds the targets set in the price control, we retain a share of the benefits, and vice versa. The incentives cover the costs of investment for additional capacity, managing capacity constraints, the costs of purchasing shrinkage gas (gas that is either used in operating the system or lost from the system during transportation) and other gas system operator costs.
Our gas transporter licence also may, in certain circumstances, allow the recovery of significant and unforeseen increases in efficiently incurred costs.
Further detailed arrangements for the industry are provided through the Network Code, which defines the obligations, responsibilities and roles of the industry participants.
During 2004, the Health and Safety Executive (HSE) and Ofgem accepted our proposal to remove the 'Top-up' arrangements from the Transco Safety Case (a document setting out our arrangements for the safe flow of gas, investigations of gas escapes, fires and explosions, and gas quality, which must be accepted by the HSE in order to transport gas) and the Network Code. Previously under the Network Code, our UK gas transmission business undertook the role of managing Top-up. This required the setting, monitoring and preservation of storage levels to protect gas stocks under prolonged and severe winter conditions. This could entail the purchase of gas from the open market to maintain the prescribed levels of gas storage stocks. In turn, this could have led to the business and the wider industry incurring significant costs if there was a shortage of gas available to the market.
Under the revised arrangements, Top-up storage monitors have been replaced by a set of 'safety monitors'. These ensure that sufficient gas is kept in the various storage facilities throughout the winter to underpin the safe operation of the network. A potential breach of a safety monitor could lead to Transco declaring a network gas supply emergency and using the established emergency procedures to avoid the breach occurring. The new framework more clearly distinguishes between our role in ensuring safety, and the market's role in delivering a secure supply.
On 20 January 2005, the Gas and Electricity Markets Authority granted its conditional consent to our application to dispose of four of our eight distribution networks. In conjunction with this, we have undertaken to use our best endeavours to implement enduring exit arrangements for the NTS by 1 September 2005, including the design of incentive schemes to support the exit arrangements.
The incentive schemes are being designed to ensure, among other things, that the NTS is incentivised, through an efficient balance of risk and reward, to release for sale the maximum capability of the network in response to demand.
Final proposals on the incentive schemes are anticipated to be published by Ofgem in summer 2005.
In November 2004, we also opened the new Gas National Control Centre. The centre represents an investment of £3.3 million and is equipped with the latest technology to cope with the increasing network and commercial complexity.
Safety
Safety performance in UK electricity and gas transmission has been encouraging. During 2004/05, there was a 20% reduction in LTIs from 10 in 2003/04 to eight in 2004/05, and we went 142 consecutive days without an LTI.
Operating performance
The winter of 2004/05 saw demand from the electricity transmission network in England and Wales hit a peak of 53.29 GW. This slightly exceeded the previous year's peak of 52.97 GW.
During 2004/05, excluding anomalous losses (defined as three or fewer customers), loss of supply totalled 55.3 MWh in 2004/05 spread across six incidents. This has only been bettered once in the last decade and represents successful delivery of 99.99998% of energy demanded during the year.
Since 1 January 2005, National Grid Company has operated under a new Transmission Network Reliability Incentive scheme. Scheme parameters have been set until 31 March 2007 and the incentive takes the form of a sliding scale. This scheme allows us to receive payments if we maintain or improve reliability of the England and Wales transmission system by delivering above average reliability of the network. The incentive target set is equivalent to a level of reliability of better than 99.9999%.
For the initial period from 1 January 2005 to 31 March 2006, there is the potential to earn additional revenue for performance better than the lower target level of loss of supply of 310 MWh, up to a maximum of 1.25% of revenue. For loss of supply in excess of 342 MWh, we can potentially lose revenue, up to a maximum of 1.875% of revenue, capped at a level of loss of 816 MWh. For each incentive year, the revenue impact takes place in the following year, so that any change in revenue due to incentive performance for the initial 15 month period will be accounted for in our allowed revenue in 2006/07.
System performance is partly monitored through system availability, including winter peak and average annual availability. Availability is reduced whenever a circuit is taken out of operation, either for planned purposes eg construction work, or as a result of a fault. Planned work is required to provide new user connections as well as the maintenance necessary to retain a high level of system reliability to ensure that licence standards are met. Over the course of 2004/05, we have maintained our average annual availability of the electricity network at 95.2% compared with 95.2% in 2003/04 and 95.8% in 2002/03, and our five-year average was 95.5% in 2004/05. System availability at winter peak demand was 97.6% in 2004/05 compared with 98.0% in 2003/04 and 98.8% in 2002/03, and our five-year average was 98.3% in 2004/05. The 0.4% reduction in system availability at winter peak comparing 2004/05 with 2003/04 reflected the increased system outage commitment due to construction, connection and maintenance work.
2004/05 saw a maximum demand for gas of 418 mcm on 28 February 2005. This was a decrease from the previous year's peak of 444 mcm and was partly due to a mild winter with a cold spell at the end of February and in early March.
The ability of the gas transmission system to transport the available gas is dependent on the performance of our compressor fleet. The compressors are used to maintain the pressure at key points on the gas transmission system. The performance of the compressor fleet is measured by the average time elapsed between breakdowns for the fleet; a longer time indicates better performance. Over 2004/05, the performance improved with the average time between compressor failures at 24% above our five-year average, compared with 11% above the five-year average in the mean time between failures in 2003/04.
Financial performance
The results of the UK electricity and gas transmission segment for the years ended 31 March 2005, 2004 and 2003 were as follows.
Years ended 31 March UK electricity and gas transmission |
2005 £m | 2004 (restated) £m | 2003 (restated) £m |
|---|---|---|---|
| Turnover | 1,930 | 1,867 | 1,893 |
| Operating costs excluding exceptional items | (1,121) | (1,108) | (1,084) |
| Adjusted operating profit | 809 | 759 | 809 |
| Exceptional items | (2) | (14) | (46) |
| Operating profit | 807 | 745 | 763 |
The £63 million increase in UK electricity and gas transmission turnover comparing 2004/05 with 2003/04 was due to higher Transmission Network Use of System charges arising from the introduction of the revised connection charging methodology under Plugs from 1 April 2004 of £32 million. The increase was also due to timing and inflationary impacts on electricity transmission revenue collection of £29 million.
The £26 million reduction in turnover comparing 2003/04 with 2002/03 was mainly due to the receipt of a £20 million one-off connection-related fee in 2002/03.
The £13 million increase in UK electricity and gas transmission operating costs, excluding exceptional items, comparing 2004/05 with 2003/04 reflected higher incentivised costs associated with the Balancing Services Incentive Scheme of £24 million and an £11 million pension deficit charge associated with the recent actuarial valuation of the electricity and gas pension schemes. This was partly offset by a £22 million charge incurred in 2003/04 as a result of the introduction of Plugs.
The £24 million increase in operating costs, excluding exceptional items, comparing 2003/04 with 2002/03 reflected the Plugs related charge of £22 million as referred to above.
Under Plugs, we have made refunds to connected parties associated with assets that were subject to capital contributions or other accelerated payment terms. The electricity transmission owner business recovers these refunds from customers under the transmission licence through Transmission Network Use of System income. The majority of the refunds have been made in 2004/05, but the recovery of the income associated with these refunds is over a more extended time period.
The UK electricity and gas transmission owner activity controllable costs shared a 1% reduction in real terms in 2004/05 from 2003/04 with a cumulative 5% reduction since 2002/03.
The £50 million increase in UK electricity and gas transmission adjusted operating profit comparing 2004/05 with 2003/04 reflected the movements in turnover and operating costs as described above.
The £50 million decrease in adjusted operating profit comparing 2003/04 with 2002/03 was mainly as a result of the Plugs one-off charge and lower connection-related fee income (see earlier discussions under operating costs) and higher depreciation reflecting extensive investment in the UK gas and electricity transmission systems. This decrease was partly offset by lower shrinkage costs, a reduction in controllable costs and other movements mainly due to timing.
Exceptional items, which explain the difference between adjusted operating profit and operating profit, relate to merger related restructuring costs.
Investment in the networks
Capital investment in the replacement, reinforcement and extension of the UK electricity and gas transmission systems in 2004/05 was £522 million, compared with £584 million in 2003/04 and £567 million in 2002/03.
In 2004/05, 41% of electricity transmission capital expenditure was related to asset replacement, reflecting the increasing need to replace transmission network assets, many of which were commissioned in the 1960s.
The decrease in overall capital investment comparing 2004/05 with 2003/04 was largely due to completion of major projects on the gas and electricity networks, despite an underlying increase in electricity asset replacement investment in 2004/05.
Investment in electricity and gas transmission systems is, by its nature, variable and is largely driven by changing sources of supply and asset replacement requirements. The gas transporter and electricity transmission licences oblige us to provide connections and capacity upon request for users wishing to use the networks.
The UK is entering a period of changing supply patterns for both gas and electricity. The sources of gas and electricity are shifting, with the decline in UK continental shelf gas reserves and the Government's emphasis on combating climate change and encouragement of renewable generation. We also continue to see a trend toward greater use of gas in power generation with the UK moving toward a low carbon economy.
We continue to work with the UK Government and Ofgem to make possible the necessary investments in the electricity transmission network to support the development of renewable energy projects. The final Transmission Investment for Renewable Generation proposals from Ofgem recognised the need to invest in networks to accommodate renewables. Funding costs for £108 million of investment will be allocated to our electricity transmission owner activity allowable revenue for the upgrade of the Anglo-Scottish interconnector (conditional on the satisfactory outcome of key planning consent issues in Scotland). The proposals also include increased rates of return of 8.8% real pre-tax for the approved baseline projects, the funding to be recovered through our Transmission Network Use of System charges. At this time, access has been sought by 10.5 GW of wind generation (3.3 GW in England and Wales and 7.2 GW in Scotland), and as the GB System Operator we have processed 65 applications. In addition to these, there is interest from another 3.4 GW (72 sites).
Due to the decline in gas production from the UK continental shelf (UKCS), our latest forecast is that the UK will import in the region of 50% of its gas requirements by the end of the decade. We have therefore seen increasing activity in providing the necessary import capability. This involves gas interconnectors and liquefied natural gas (LNG) importation facilities, such as the Norwegian interconnector, the LNG facility at Milford Haven and the LNG facility we are developing on the Isle of Grain, which will come on stream this year. It is anticipated that additional Norwegian gas supplies will be delivered at Easington terminal, and so will require further gas transportation construction from Pannal to Nether Kellett for 2007/08. The Milford Haven importation facility is also due to be connected for the 2007/08 gas supply year and will require the reinforcement of the existing gas transportation network with approximately 168 miles of new pipeline in South Wales and Gloucestershire to cater for the increase in flow. The projects to meet the changing supply sources will result in a total of over £750 million in capital expenditure on the gas transmission system over the next five years.
The bulk of the current electricity transmission network was installed during the 1960s and 1970s, with main plant asset lives typically of between 40 to 50 years. Over the next few years, we anticipate substantially increasing investment on replacing parts of our UK electricity network as these assets will be due for renewal. In addition, parts of the gas transmission network are reaching the end of their lives. These are mainly compressor stations, control systems and valves (ie above ground assets and not the high pressure pipes). This, together with work required to meet changing supply sources, means that the UK electricity and gas transmission business will be embarking on a significant increase in investment and network renewal.
In order to meet the increasing programme of work, we will be recruiting approximately 100 staff, project and site engineers over the next two to three years to ensure we can deliver the increased work programme. We will also be exploring ways to work more efficiently and collaboratively with major suppliers and contractors to manage the increase in workload effectively.
US electricity transmission
Background information
In the US, we own and operate an electricity transmission network of approximately 14,000 miles. Our US electricity transmission business operates facilities at voltages ranging from 69 kV to 345 kV, utilising nearly 9,000 miles of overhead lines and 541 substations. We are the largest electricity transmission service provider in the northeastern US by reference to the length of these high-voltage transmission lines. In addition, we own and operate a 139 mile direct current transmission line rated at 450 kV that is a key section of an interconnector between New England and Canada.
We provide electricity transmission in New York state through Niagara Mohawk Power Corporation and in New England principally through New England Power Company.
In addition, in the midwestern US, our GridAmerica business manages a range of electricity transmission operations on behalf of its participant utilities. These include operational planning, outage management and scheduling of transmission service. It was the first multi-system independent transmission company and was formed under agreements with Ameren, FirstEnergy, Northern Indiana Public Service Company (NIPSCO) and the Midwest Independent System Operator (MISO).
During April 2005, Ameren notified our US electricity transmission business and its fellow GridAmerica participants that it will withdraw from GridAmerica, effective 1 November 2005. Together with FirstEnergy and NIPSCO, we evaluated GridAmerica's viability given the current industry environment, their respective long-term corporate strategies and Ameren's departure, and ultimately agreed to cease operations also effective 1 November 2005. The Group will be looking to reapply the skills and knowledge brought to its participation in GridAmerica as it seeks to develop interests in North America.
Regulation
New England Power Company collects electricity transmission revenues from its distribution company affiliates under regional and local tariffs approved by the Federal Energy Regulatory Commission (FERC) which allow it to recover the costs of providing transmission services, with a return on capital. Niagara Mohawk Power Corporation collects the transmission business revenues under FERC and state tariffs, with state provisions similar to the distribution regulation discussed in Regulation within US Distribution of the Operating Review.
GridAmerica receives revenues from the MISO under a rate schedule approved by the FERC, along with management fees paid by the three participant utilities. This will continue until November 2005, when GridAmerica operations will cease.
The US electricity transmission business in the Northeast currently operates within two independent system operators (ISOs), ISO New England and New York ISO, which administer the markets and provide oversight of transmission in their respective regions.
New England Power Company operates co-operatively with other New England transmission owners within ISO New England. The transmission owners are responsible for certain aspects of operation, such as field operations and switching operations, and the ISO has responsibility for overall system operation and coordinating the regional transmission for the whole of New England. It is also responsible for operating reliable and efficient wholesale electricity markets. On 1 February 2005, ISO New England became the regional transmission organisation (RTO) for New England. Becoming an RTO gives ISO New England more independence from market participants and a stronger right to require transmission investments by the transmission owners under a regional system expansion planning process.
By becoming a member of the New England RTO, New England Power Company can seek a higher allowed return for our New England assets, in accordance with the FERC's proposed transmission pricing policy. This application for an increased return is under review by the FERC.
Safety
US electricity transmission recorded no employee LTIs during 2004/05, extending the time since the last LTI to 23 months.
Operating performance
Over the course of 2004/05, our estimated average annual network availability was 98.55%. Overall average network availability was similar in New England and New York, for both summer and winter.
Last year saw an increase in the number of disturbances experienced on our US electricity transmission networks, much of which we attribute to lightning activity which was 85% above the 10-year average and almost five times the prior year's level. We are actively analysing the impact from lightning and have undertaken a project to consider a range of lightning mitigation measures.
Financial performance
The results of the US electricity transmission segment for the years ended 31 March 2005, 2004 and 2003 were as follows.
Years ended 31 March US electricity transmission | 2005 £m | 2004 (restated) constant currency basis £m | 2003 (restated) constant currency basis £m | 2004 (restated) £m | 2003 (restated) £m |
|---|---|---|---|---|---|
| Turnover | 283 | 285 | 346 | 318 | 407 |
| Operating costs excluding exceptional items and goodwill amortisation | (160) | (166) | (237) | (185) | (279) |
| Adjusted operating profit | 123 | 119 | 109 | 133 | 128 |
| Exceptional items | (3) | (8) | (3) | (9) | (4) |
| Goodwill amortisation | (18) | (17) | (18) | (19) | (21) |
| Operating profit | 102 | 94 | 88 | 105 | 103 |
The average exchange rates used to translate the results of US operations during 2004/05, 2003/04 and 2002/03 were $1.87:£1, $1.68:£1 and $1.59:£1 respectively. In order to illustrate underlying performance, the impact of exchange rate movements has been separated from other changes by also presenting the operating results for 2003/04 and 2002/03 on a constant currency basis, using the average exchange rate for 2004/05 of $1.87:£1. The 2003/04 and 2002/03 results are discussed below as if the 2004/05 exchange rate had applied.
The £2 million reduction in US electricity transmission turnover comparing 2004/05 with 2003/04 was mainly the result of a decrease in New England Power Company's operating costs which flow through to revenue.
The £61 million reduction in turnover comparing 2003/04 with 2002/03 was primarily related to the transfer of £76 million of New England Power Pool billings and costs from transmission to distribution segments. This decrease in turnover was partially offset by increased revenues from higher operating costs in New England Power Company which flowed through to revenue.
The £6 million reduction in US electricity transmission operating costs, excluding exceptional items and goodwill amortisation, comparing 2004/05 with 2003/04 was primarily related to reduced payroll and lower pension and other post-retirement benefit costs.
The £71 million reduction in operating costs, excluding exceptional items and goodwill amortisation, comparing 2003/04 with 2002/03 was primarily related to a transfer of costs associated with New England Power Pool billings as discussed above. This was partially offset by the increase in New England Power Company operating costs which flow through to revenue.
The £4 million increase in US electricity transmission adjusted operating profit comparing 2004/05 with 2003/04 was mainly due to lower operating costs in New York as a result of lower payroll and pension costs and increased returns for New England Power Company.
The £10 million increase in adjusted operating profit comparing 2003/04 with 2002/03 was primarily due to the pass-through allowance for certain exceptional reorganisation costs and the first six months profits from GridAmerica of £2 million.
Exceptional items and goodwill amortisation explain the difference between adjusted operating profit and operating profit. For 2004/05, exceptional items were principally attributable to restructuring costs. In 2003/04, exceptional items included £5 million in connection with voluntary early retirement offers.
Investment in the networks
Capital investment in the replacement, reinforcement and extension of the US electricity transmission networks in 2004/05 was £74 million, compared with £53 million in 2003/04 and £49 million in 2002/03. These amounts are given using the respective average exchange rates for 2004/05, 2003/04 and 2002/03.
The increase in capital expenditure comparing 2004/05 with 2003/04 reflected additional planned asset replacement investments in both New England and New York to ensure the ongoing safety, environmental and reliability performance of the system.
We expect a significant increase in investment in New England to deliver our regional system expansion planning process projects. There will also be an increase in investment in New York in order to address asset replacement requirements and increase safety and reliability of the system.