EXHIBIT 10.2

FINANCIAL HIGHLIGHTS

ONE SCOTTISHPOWER

We are one company, managing regulated and competitive businesses in the UK and US to service electricity and gas customers. We have one clear strategic aim: to become a leading international energy company.

	2002		2001
Turnover	£	6,314m	£	6,349m
Operating profit*	£	944m	£	970m
Profit before tax*	£	567m	£	628m
Earnings per share*		26.12p		27.86p
Dividends per share**		27.34p		26.04p

* Before exceptional items and goodwill amortisation

** Cash dividends excluding dividend in specie’ on demerger of Thus

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BUSINESS REVIEW—DESCRIPTION OF BUSINESS

Description of business

Scottish Power plc (“ScottishPower”) is an international energy business listed on both the New York and London Stock Exchanges. Through its operating subsidiaries, the company serves five million homes and businesses in the western US and across the UK. It provides electricity generation, transmission, distribution and supply services in both countries, whilst the company’s US activities extend to coal mining and, in Britain, ScottishPower also supplies gas. In the year to 31 March 2002, the sales revenues of the continuing business of the group were £5.5 ($7.8) billion.

Since its creation upon privatisation in 1991, ScottishPower has developed by organic growth in the UK electricity and gas markets, through strategic acquisitions in the UK and by the merger with PacifiCorp in the US. During 2001/02, the group exited the financial services market and appliance retailing in the UK and sold a non-strategic business in synthetic fuel production belonging to US subsidiaries. The UK telecommunications and internet business, Thus, was demerged to the company’s shareholders and the UK water and wastewater company, Southern Water, sold, thereby concluding the process of redefining ScottishPower as an international energy business.

Strategic context

Having completed its strategic disposals, ScottishPower’s strategy is to become a leading international energy company, managing both regulated and competitive businesses in the US and UK to serve electricity and gas customers. The regulated businesses provide a base for steady growth through consistent investment and proven skills in operational and regulatory management. In competitive activities in which the group has local market knowledge and skill advantages, it will seek to enhance margins through the integration of generation, trading and customer services, again underpinned by best-in-class operational performance. The aim is to deliver steady growth in value and earnings per share by capitalising on the opportunities afforded by substantial positions in both the US and UK markets, organising the skills and resources deployed in these different marketplaces within one common ScottishPower business framework: but one which takes account of essential differences between the US and UK situations.

Shared, and increasingly integrated, skills in network management are enhancing performance in the US and the UK electricity transmission and distribution businesses. Similarly, both the strongly growing, US competitive energy business, PacifiCorp Power Marketing, Inc. (“PPM”), and the competitive UK energy business are taking market-leading positions in windfarm developments and investing in natural gas storage facilities: two key areas of future value creation. With UK energy markets now fully competitive but US states adopting differing approaches to the introduction of energy competition, the company’s skills in the management of legislative and regulatory relations are engaged in a Multi-State Process (“MSP”) with the six states the company serves in the US. Through MSP, the participants are working to clarify roles and responsibilities on issues such as cost allocations for future generation resources, ability to implement state energy policy objectives independently and entitlement to the benefits of PacifiCorp’s existing assets.

The ScottishPower strategy involves a consistent commitment to achieving (or, where the regulatory process permits, bettering) target returns from regulated businesses, building sustainable value in competitive energy markets and actively managing risk, both operational and financial. In 2001/02, the strategy was delivered through three divisions concentrating on US energy needs, the evolving competitive market for UK energy and the group’s UK infrastructure assets. The 2001/02 Accounts and Financial Review reflect this segmentation which is further described under “Accounting Policies and Definitions” (page 56). With PPM developing substantive operations, UK energy market price controls lifted from 1 April 2002 and the sale of Southern Water, the group’s 2002/03 operations are managed through four businesses:

• PacifiCorp

• PacifiCorp Power Marketing, Inc.

• UK Division

• Infrastructure Division

In each of the US and the UK, there is a business operating under regulation and one in competitive market conditions.

        In the US, PacifiCorp operates as a regulated electricity business with significant mining affiliates—and the competitive energy business is PPM. Since 31 December 2001, both have been subsidiaries of PacifiCorp Holdings, Inc. (“PHI”) a non-operating, US holding company, itself an indirect wholly-owned subsidiary of ScottishPower. On 4 February 2002, PHI also became the parent of PacifiCorp Group Holdings (“Holdings”) which owns the shares of subsidiaries not regulated as domestic electricity providers, including PacifiCorp Financial Services, Inc. (“PFS”). The transfers to PHI facilitate the further separation of the company’s non-utility operations in the US from the regulated US business, PacifiCorp.

In the UK, the regulated Infrastructure Division operates electricity transmission and distribution subsidiaries of the wholly-owned UK holding company Scottish Power UK plc (“SPUK”) whilst other SPUK subsidiaries operating in the now competitive UK energy markets comprise the group’s competitive UK Division, covering its UK generation assets, commercial and trading activities and energy supply business units.

All four businesses have a strong commitment to class-leading operational performance as the route to the creation of shareholder value.

PacifiCorp

In November 1999, PacifiCorp and ScottishPower completed a merger under which PacifiCorp became an indirect subsidiary of ScottishPower. As a result of the merger, PacifiCorp developed and commenced its Transition Plan to implement significant organisational and operational changes arising from the strategic decision to focus on its electricity businesses in the western US.

Principal business activities

PacifiCorp conducts its retail electricity supply operations as Pacific Power and Utah Power, operating from Portland, Oregon and Salt Lake City, Utah, respectively, and engages in power production and sales on a wholesale

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basis under the name PacifiCorp. Through its mining affiliates, PacifiCorp is one of the 20 largest coal producers in the US.

Power production and fuel supply

PacifiCorp owns or has interests in generating plants with an aggregate nameplate rating of 8,269 megawatts (“MW”) and plant net capability of 7,815 MW, see Table 1 (page 27). During 2001/02, approximately 5% and 63% of PacifiCorp’s energy requirements were supplied by its hydro-electric and thermal generation plants, respectively. The remaining 32% was supplied by purchased power. The contribution of thermal energy was reduced during the year by the outage at the Hunter plant, which lasted from late November 2000 to early May 2001. With its present generating facilities, under average water conditions, PacifiCorp would expect that approximately 6% of its energy requirements for 2002/03 would be supplied by its hydro-electric plants and 66% by its thermal plants. Of the balance, 13% would be obtained under existing long-term purchase contracts, the remaining 15% being secured through short-term purchase agreements.

At 31 March 2002, PacifiCorp had 218 million tons of recoverable coal reserves that are mined by PacifiCorp and are dedicated to nearby PacifiCorp operated generating plants, see Table 2 (page 28). During 2001/02, these mines supplied approximately one-third of PacifiCorp’s total coal requirements. Coal is also acquired through long-term and short-term contracts of which eight long-term contracts, having remaining terms ranging from 3 to 20 years, account for some 45% of the forward commitment at 31 March 2002.

PacifiCorp has also entered into long-term, fixed price natural gas contracts to supply natural gas to its owned gas-fired generation facilities as well as the leased West Valley Units. These long-term contracts meet 100% of the expected needs for natural gas at these facilities until 2004.

In light of the growing demand within its service area, PacifiCorp obtained permits and other approvals to install a 120 MW permanent peaking facility in Utah in time to mitigate a portion of the calendar 2002 peak demand. It is also transacting on the results of a comprehensive energy solicitation proposal that resulted in more than 50 responses from 30 prospective suppliers to meet Utah’s forward energy requirements. To provide longer-term solutions, PacifiCorp is working with regulators and other stakeholders to develop an Integrated Resource Plan to identify the least cost and lowest risk approach to supplying its service area with power over the next 20 to 25 years.

Wholesale sales and purchased power

PacifiCorp’s wholesale sales complement its retail business, enhance the efficient use of its generating capacity over the long-term and, because PacifiCorp’s transmission system connects with power providers in the western states with widely varying generation plant characteristics, facilitate load shaping, balancing and hedging arrangements. In the generally volatile market conditions of 2001/02, both short-term market prices and long-term contract volumes dropped. Net wholesale volume fell some 11% year-on-year to 34% of total gigawatthours (“GWh”) sold in 2001/02. In addition to its base of thermal, renewable and hydro-electric generation assets, PacifiCorp uses a mix of long-term and short-term firm power purchases and non-firm purchases to meet its load obligations, wholesale obligations and its balancing requirements. Long-term firm power purchases supplied 12% and short-term firm and non-firm power purchases supplied 21% of PacifiCorp’s total energy requirements in 2001/02. Lower volumes of long-term wholesale sales allowed both long and short-term purchase volumes to be reduced with a larger proportion of purchases used to meet load requirements and also to reduce the purchase of short-term spot power to balance load.

PacifiCorp currently purchases, annually, 925 MW of firm capacity from the federal Bonneville Power Administration (“BPA”) pursuant to a long-term agreement. The purchase amount declines to 750 MW annually in July 2003 and again to 575 MW in July 2004 until August 2011. PacifiCorp’s annual payment under this agreement for the period ended 31 March 2002 was $60 million. The price for this capacity is a per MW charge, therefore the costs associated with this agreement will decline as the MW purchase declines. The price is adjusted by the rate of change in the BPA’s Average System Cost. A slight decline is expected in 2003. The next scheduled price change will be in October 2006. Under the requirements of the Public Utility Regulatory Policies Act of 1978, PacifiCorp purchases the output of qualifying facilities constructed and operated by entities that are not public utilities. During 2001/02, PacifiCorp purchased an average of 104 MW from qualifying facilities, compared to an average of 109 MW in 2000/01.

Retail electricity sales

PacifiCorp serves approximately 1.5 million retail customers in service territories aggregating about 136,000 square miles in portions of six western states. The geographical distribution of PacifiCorp’s retail electricity operating revenues for the year ended 31 March 2002 was Utah, 39%; Oregon, 32%; Wyoming, 13%; Washington, 8%; Idaho, 6%; and California, 2%. These proportions remain substantially the same year-on-year. (PacifiCorp is currently seeking to exit operations in California. See “Proposed asset sale” page 12.)

        The PacifiCorp service area’s diverse regional economy helps mitigate exposure to economic swings. In the eastern portion of the service area, where customer demand peaks in the summer when irrigation and cooling systems are heavily used in Wyoming and eastern Utah, the main industrial activities are mining and extracting coal, oil, natural gas, uranium and oil shale. In the western part of the service territory, mainly consisting of Oregon and southeastern Washington, customer demand peaks in the winter months due to space heating requirements and the economy generally revolves around agriculture and manufacturing, with pulp and paper, lumber and wood products, food processing, high technology and primary metals being the largest industrial sectors. During 2001/02, no single retail customer accounted for more than 1.4% of PacifiCorp’s retail electricity revenues and the 20 largest retail customers accounted for 14% of total retail electricity revenues. Trends in energy sales by class of customer are set out in Tables 3, 5 and 6 (page 28).

Retail energy sales for PacifiCorp have grown at a compound annual rate of 1.8% since 1996: however, this has been affected

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by a decrease in GWh sales of about 2.0% during 2001/02. This is a consequence of extreme volatility and unprecedented high price levels, which characterised the western US wholesale energy markets, and deteriorating economic conditions across the US, which impacted the PacifiCorp service territory during that period. In order to meet its obligations to serve regulated customers and in the expectation of continuing high spot prices in the balancing market, PacifiCorp purchased electricity in the forward market, primarily for delivery over the June to September period of 2001. The aim was to mitigate the impact of then anticipated high prices in excess of those included in retail rates, in particular for peak demand balancing load. Western US power costs, however, declined abruptly, from the unprecedented highs of the spring of calendar 2001, in the face of the price-cap mechanism for the western US introduced by the Federal Energy Regulatory Commission (“FERC”) and other market factors. This left PacifiCorp with actual net power costs during the summer of 2001 exceeding the levels included in retail rates. During the latter half of 2001/02, however, PacifiCorp experienced electricity prices that were at levels consistent with those historically allowed in cost-of-service rates charged to customers.

Some of the net power costs in excess of those included in prevailing retail rates at that time will be recovered by allowed rate increases or temporary surcharges. PacifiCorp has reached settlement agreements in Utah, Oregon and Idaho to recover costs for electricity in excess of costs included in retail rates. Under US Generally Accepted Accounting Principles (“GAAP”) excess net power costs, where approved by regulators, are initially deferred as regulatory assets and recovery subsequently sought through rate filings. At 31 March 2002, deferred excess power costs totalled $392 million (including carrying charges), of which $308 million were the subject of filings made. Rate adjustments awarded so far total approximately $171 million. Under UK GAAP, all PacifiCorp’s net power costs are charged to the profit and loss account when incurred. There is, therefore, a time lag between the recognition of allowable excess power costs under UK GAAP compared to US GAAP, which will benefit future UK GAAP reported earnings. General rate adjustments granted in the past year have an annualised value of approximately $125 million.

For the periods 2003 to 2006, the average annual growth in retail megawatthour (“MWh”) sales in PacifiCorp’s franchise service territories is estimated to be about 2.4%, excluding the potential effects of decreased demand from price increases and conservation efforts. If price increases occur in the region, PacifiCorp believes that demand growth may slow.

During 2001/02, PacifiCorp continued to operate its electricity distribution and retail sales business as a regulated monopoly throughout most of its franchise service territories. In the longer term, customer demand for choice may eventually lead to retail competition in each state. Deregulation in the states in which PacifiCorp operates has varied and, in general, is not greatly advanced. However, as the electricity industry evolves toward deregulation, PacifiCorp may lose retail energy sales to other suppliers but expects to have opportunities to sell any excess power in wholesale markets. PacifiCorp’s actual results will be determined by a variety of factors, including the outcome of deregulation in the electricity industry, economic and demographic growth and competition.

Proposed asset sale

In October 2001, PacifiCorp and Nor-Cal Electric Authority reached an agreement in principle for the sale of PacifiCorp’s California electricity distribution assets. The California Public Utilities Commission (“CPUC”) turned down a previous agreement between the parties. If a definitive agreement is reached, it will have to be approved by the CPUC.

PacifiCorp Power Marketing, Inc.

The Energy Policy Act, passed in 1992, opened wholesale competition to energy brokers, independent power producers and power marketers. The group’s own competitive energy business, PPM, serves a wide variety of wholesale energy customers including municipal agencies, public utility districts and investor-owned utilities. These customers are primarily located in wholesale energy markets served by the 1.8 million square mile Western Electricity Coordinating Council (“WECC”) service territories in the western US. In addition to its active engagement in the west, PPM is currently developing wind generation projects in the mid-western US and developing gas storage/hub services projects in several regions.

PPM commenced substantive operations during 2001. In July 2001, PPM brought on-line the 484 MW Klamath Cogeneration Plant, of which it has access to 227 MW base load and 10 MW peaking capacity. Following Klamath, the Stateline windfarm commenced operations by autumn 2001, of which PPM purchased the entire output. Stateline is currently rated 263 MW capacity, with expansion planned for later in 2002. PPM also constructed two peaking plants providing 260 MW (soon to be 300 MW) of additional capacity. The equivalent output and energy for these facilities has been sold under long-term contracts, thereby providing PPM with a balanced portfolio of assets and long-term contracts.

PPM further expanded its activities in January 2002 with the purchase of a 40% interest in an underground natural gas storage facility and hub service business located 80 miles west of Edmonton, Alberta, and PPM is now one of the operators of the facility. The facility is connected to the major pipelines that transport gas to Canadian and US markets.

        For the future, PPM is targeting 15-20 renewable development opportunities which it believes the market will support based upon competitive costs and increasing public support for renewables. PPM is also targeting two to four new gas storage developments that are strategically located and cost competitive. PPM is a western US leader in the supply of renewable energy and is committed to sustainable and clean energy development for the future, as demanded by the market.

UK Division

With the ending of residual price controls on residential electricity on 31 March 2002, the UK gas and electricity markets became fully competitive, although the Gas and Electricity Markets Authority (“the Authority”) and the Office of Gas and Electricity Markets

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(“Ofgem”) continue to enforce licence conditions and regulate quality of service. During 2001/02, and in line with a timetable agreed with the Department of Trade and Industry (“DTI”) to give effect to the requirements of the Utilities Act 2000 (“Utilities Act”), the UK Division’s now competitive generation, trading, supply and service businesses were separated from the still price-regulated UK networks businesses in the Infrastructure Division. Five new wholly-owned subsidiaries of Scottish Power UK plc now form the UK Division: Scottish Power Generation Limited owns and operates the power stations and other generation assets in the British Isles and holds the group’s generation licence; ScottishPower Energy Trading Limited and ScottishPower Energy Trading (Agency) Limited deal in gas, electricity and coal at the wholesale level and in the trading instruments and agreements which constitute the market balancing mechanisms for the competitive energy market in the UK; ScottishPower Energy Retail Limited is the gas and electricity supply company and holder of the group’s supply licences, managing pricing, selling, billing and receipting for gas and electricity supply to both business and domestic customers and dealing with enquiries arising in the course of this business; and SP Dataserve Limited is the data management and metering company, providing a meter reading service to its supply business customers and managing the data processes which underpin customer registration and billing in the competitive energy market.

An integrated divisional management team seeks competitive advantage for ScottishPower by optimising the energy value chain, maximising the value of both generation and supply assets in a period of uncertainty in wholesale energy markets. This uncertainty derives, in part, from the continuing structural and contractual changes in the market and from the potential impact of the, as yet incomplete, review of energy policy by the UK government. As an active market participant, the division engages fully in regulatory and contractual debate and in the consultation processes surrounding the Government’s review of energy policy. In the meantime, it aims to leverage the benefits of its flexible generation asset base and commercial trading operations and to deliver sustained earnings through improved business processes and customer service.

Principal business activities

The group’s UK Division operates ScottishPower’s generating stations in the British Isles, deals in the wholesale trading of electricity, gas and coal and is responsible for energy supply: the sales and marketing of electricity and gas to customers throughout Great Britain, together with the associated customer registration, billing and receipting processes and handling enquiries in respect of these services.

Power plant portfolio, fuel strategy and generation sales

ScottishPower has access to some 4,500 MW of owned generating capacity, see Table 7 (page 29) comprising coal, gas, hydro-and wind-power generation assets, giving the division a particularly flexible portfolio. Gas-fired generation capacity in England & Wales was boosted to approximately 1,000 MW during 2000/01 by the purchase of the Rye House station and the start of commercial operation of the Brighton station in which ScottishPower has a 50% interest. Acquisition of additional thermal generation capacity is kept under continuing review. In 2001/02, the windfarm business continued to expand, a high wind-speed site with 30 MW peak output at Beinn an Tuirc in Kintyre being commissioned and planning applications for a further 294 MW submitted. The division now has projects in Scotland totalling almost 500 MW in planning or detailed environmental assessment, with a further 55 MW in joint venture projects in England & Wales, to ensure that the company target of 10% generation from renewables by 2010 is met.

ScottishPower’s fuel purchasing strategy is based upon the objective of achieving competitive fuel prices while balancing the need for security and flexibility of supply. The major components of the fuel portfolio are coal and gas. The division has four long-term contracts with terms of greater than five years for supply from major gas producers.

Generation output was traded in order to hedge risk and optimise the position in the balancing market. Some 20 terawatthours (“TWh”) were despatched, both to contribute towards the approximately 33 TWh of retail and wholesale demand provided by the division and to maintain export volumes through the interconnectors to England & Wales and, from January 2002, to Northern Ireland.

Energy trading and commercial arrangements

In addition to its own generation capacity and long-term bulk gas contracts (which can be used to service generation plants or the gas supply business), ScottishPower has access to additional generation under contract. Through its commercial and trading operations, the division uses medium and short-term contractual arrangements to complete its energy purchase requirements and to sell its generation output into the electricity market in Scotland and, through the interconnectors, to England & Wales and Northern Ireland. Proposals for transmission access and the England-Scotland interconnector will be key to ScottishPower’s acceptance of the proposed British Electricity Trading and Transmission Arrangements (“BETTA”) which are expected to become effective during 2004.

        Electricity, gas and coal trading, within Trading UK, secures competitive advantage for the group through trading and optimising its position across the energy value chain, continuously evaluating and managing risk exposure. ScottishPower’s Hatfield Moors gas storage site enhances the flexibility of the trading position, both in meeting peak demands of supply customers and responding to the volatility of gas prices between mid-week and weekends. In addition, the gas contract linked to the Rye House power station purchase has been re-negotiated to allow the gas to be sold out or used elsewhere in the business, giving yet more trading flexibility. Further investment in gas storage facilities is in hand.

From 27 March 2001, New Electricity Trading Arrangements (“NETA”) were introduced, replacing the Pool market established at privatisation with market-based arrangements more akin to those in commodity markets and comprising a three-tier trading system: a forward and futures market, a short-term bilateral market and a balancing mechanism with a settlement process for imbalances and penal imbalance charges, requiring highly

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efficient forecasting, trading and risk management on the part of all participants.

The NETA arrangements encourage all generators to find buyers for their output, by offering them competitive prices, and all suppliers to contract with generators to purchase sufficient electricity to meet their customers’ demand. Imbalances between actual and contracted positions are settled through the balancing mechanism. The pay-as-bid and balancing process exposes market participants to the costs and consequences of their actions, and therefore leads to more cost-reflective prices and more effective management of risk. Under the Nuclear Energy Agreement (“NEA”) of 1990, ScottishPower and Scottish & Southern were contracted, until 2005, to purchase the entire output from British Energy’s nuclear plants in Scotland. The pricing formula contained in the NEA is based upon Pool Price and ScottishPower is seeking clarification from the Court of Session as to whether or not the NEA is capable in law of continuing after the introduction of NETA and/or the cessation of the Pool Price and, if so, the contractual terms upon which it can continue.

Energy supply

Since September 1998, when competition was extended to residential electricity customers, the strategic focus of the ScottishPower energy supply business has been the defence of its core markets, residential and small business customers in the ScottishPower and Manweb home areas, whilst seeking profitable additional business outside these historical regional boundaries. Retention of home area residential customers remains broadly in line with the industry average of 67%. Targeted sales efforts and strategic marketing alliances, such as those with Sainsbury’s and Union Energy, have helped develop a Britain-wide customer base of some 3.5 million energy accounts, 0.9 million being gas supplies. The business’ Customer Service Guaranteed Standards were maintained in the year ended 31 March 2002 at the high level set in the previous year, with over 99.99% of all electricity services provided currently matching or exceeding regulatory standards. The continuing improvement in service levels was recognised in November 2001 when JD Power and Associates judged ScottishPower the number one UK domestic gas supplier for customer satisfaction.

Both service improvements and economies of scale derive from integrated systems and the move to a single billing platform. The priorities remain accelerating the reduction of servicing costs to benchmark levels and enabling referral of customers to sales and retention channels suited to an increasingly competitive market. In mid-2001, the division’s e-business site was upgraded to allow customers to manage their own accounts on-line if they wish. Customers can now enter meter readings, view previous bills, create and pay new ones and switch to new internet tariffs through which they can share in the savings generated by the low costs of managing accounts on-line.

Metering and data management

In the competitive energy market, meter reading and meter operation form parts of an integrated data management process, also covering customer registration, billing record set-up and agent registration. SP Dataserve operates end-to-end process management in order to maximise efficiencies in the provision and control of registration and metering data. Meter reading and meter operation are characterised by a large regional field force, working from home, which carries out over 12 million customer visits a year and operates in a competitive market covering activities (from meter installation and meter operation to data collection) for gas, electricity and water supply business customers.

Infrastructure Division

During 2001/02, the UK wires businesses were restructured in line with a timetable agreed with the DTI to give effect to the requirements of the Utilities Act and to develop further the commercial focus applied to the management of these assets. Three wholly-owned subsidiaries of Scottish Power UK plc; SP Transmission Limited, SP Distribution Limited and SP Manweb plc, are the “owner companies” holding the regulated assets and transmission and distribution licences. They now act as an integrated business unit to concentrate expertise on regulatory issues. A further wholly-owned subsidiary of Scottish Power UK plc, SP Power Systems Limited, (“Power Systems”), provides asset management expertise and conducts the day-to-day operation of the networks on behalf of the asset-owner business. Strict commercial disciplines are applied at the asset owner-service provider interface. The move towards fully competitive provision of connections to distribution networks is supported by Core Utility Solutions Limited, a joint venture with Alfred McAlpine Utility Services Limited in which ScottishPower has an indirect beneficial interest of 50%.

An integrated senior management team within the Infrastructure Division applies the benefits of growing expertise in asset ownership, financing and operational service provision to the management of the group’s regulated networks businesses in both the US and the UK.

Principal business activities—transmission and distribution

        ScottishPower owns and manages a substantial UK electricity distribution and transmission network which extends to 115,633 km, with 65,590 km of underground cables and 50,043 km of overhead lines network, comprising both the distribution system to customers in its two authorised areas and, in Scotland, its high voltage transmission system (132 kilovolts (“kV”) and above, including those parts of the England-Scotland interconnector which are in its Scottish authorised area). Table 8 (page 29) shows key information with respect to the business’ transmission and distribution services in 2001/02. These networks are operated under licences issued by the Authority and held by the transmission and distribution businesses, which are entitled to charge for the use of the systems on terms approved by the Authority under various price control formulae. The management focus of the transmission and distribution business unit is to outperform allowed regulatory returns from the provision of efficient, coordinated and economical networks which are open to licensed users on a non-discriminatory basis (in order to facilitate competition in generation and supply) and operated to approved standards of safety and reliability.

The income derived from the distribution business is dependent on the demand for electricity by customers in the licenced areas. Demand for electricity is affected by such factors as growth and movements in

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population, social trends, economic and business growth or decline, changes in the mix of energy sources used by customers, weather conditions and energy efficiency measures. Tables 9 and 10 (page 29) set out the demand in GWh by customer type within the broadly stable levels of electricity transported over the distribution systems in the ScottishPower and Manweb home areas during the five most recent financial years.

Principal business activities—asset management

Within the Power Systems business unit, the focus continues to be on reducing costs and improving service. Its principal business activities involve the construction and refurbishment of the UK transmission and distribution systems, their maintenance and related fault repair. Power Systems acts as the major service provider to the ScottishPower transmission and distribution business unit and as the primary customer contact agent for network-related matters. Power Systems continues to focus strongly on the efficient delivery of these services under contract. Power Systems has entered into a joint venture with Alfred McAlpine Utility Services Limited, called Core Utility Solutions Limited, to take advantage of the opportunities presented by the requirement for competitive provision of connections to distribution networks.

Discontinued activities

US synthetic fuel operations

In October 2001, PacifiCorp sold its synthetic fuel operations and, in addition to the initial sale consideration, may receive quarterly royalty payments from the purchaser until October 2007. The synthetic fuel business was intended to qualify for tax credits but PacifiCorp did not have sufficient qualifying tax liabilities to make effective use of the offset potential.

US leasing and financial services

During the first quarter of 2001/02, certain aircraft owned by subsidiaries of PFS were sold. Holdings continues to liquidate portions of the loan and leasing portfolios of PFS.

UK appliance retailing

A decision to withdraw from the loss-making UK Appliance Retailing business was announced in June 2001. The disposal of 98 stores to Powerhouse Retail Limited was finalised in October 2001 and the closure of the remaining operations is now complete.

UK telecommunications—Thus

On 19 March 2002, ScottishPower’s former controlling interest in Thus Group plc (“Thus”), was demerged to ScottishPower ordinary shareholders, in order to release its value to shareholders and to allow the management of ScottishPower to focus on the company’s core operations. Thus provides data and telecoms, internet and call centre services, operating throughout the UK and wholly focused on the corporate and small and medium enterprise markets. In its results for the year to 31 March 2002, Thus restated its belief that the refinancing which accompanied the demerger will leave it in a position fully to finance its business plan on an independent basis through to the point where it becomes cash flow positive.

UK water and wastewater services—Southern Water

The sale of Southern Water to First Aqua Limited, a company specifically formed to undertake the acquisition, was announced on 8 March 2002 and concluded on 23 April 2002. Southern Water operates in an area of approximately 10,450 km² in the southeast of the UK and has a coastline stretching, including the Isle of Wight, 1,250 km from within the Thames Estuary to just beyond the Solent. It collects wastewater from approximately 1.7 million premises and supplies water to approximately 1 million and is one of the 10 water and wastewater companies operating in England and Wales.

Southern Water supplies, on average, 578 million litres of water per day, which is pumped through 13,327 km of water main by 541 pumping stations. Southern Water’s 104 water treatment works treat water from 130 water sources in the region with 72% of water supplied coming from underground sources, 22% abstracted from rivers and 6% taken from four impounding reservoirs, which have a total storage capacity of 42,390 million litres. In all cases, protection against bacteria and other micro-organisms throughout the distribution system to the point of use at the customers’ taps is maintained by a residual level of chlorine. Southern Water monitors water quality through a programme in which samples are analysed regularly for both microbiological and chemical parameters. Losses through leaks in the Southern Water distribution system were reduced to the target level of 10.9% in 2000/01, compared to 26% just before the time of privatisation.

        Southern Water has 388 wastewater treatment works (“WTWs”), which treat sewage pumped through 20,885 km of sewer by 1,975 pumping stations. WTWs provide various types of treatment and, under the Water Resources Act 1991, are granted consents by the Environment Agency (“EA”) to discharge sewage effluent to controlled waters. The disposal of sludge produced by WTWs is strictly controlled. Over 85% of the 90,900 tonnes of dry solids per year produced at Southern Water’s WTWs is further recycled, using processes controlled by an EU directive, to produce a soil conditioner sold to the agricultural industry. As part of the treatment process to meet current bathing water standards, Southern Water has 7 marine treatment works and 30 long sea outfalls around the coastline of its region. Under the EU Bathing Water Directive, the EA tests the 79 designated beaches in the Southern Water region, taking at least 20 samples during the bathing water season (1 May to 30 September) at each identified bathing beach. Results may be published and posted by district councils on the beaches concerned. In the 2001 bathing season, only one beach out of 79 failed the compliance tests.

Group employees

US businesses

PHI and its subsidiaries had 6,387 employees at 31 March 2002. Of these, 5,495 were employed by PacifiCorp, 782 by its mining affiliates and 12 by PFS and other subsidiaries. In addition, at 31 March 2002, PPM had 98 employees.

As a result of the merger with ScottishPower, PacifiCorp developed and is delivering a Transition Plan to implement significant organisational and operational changes. As part of this Transition Plan, PacifiCorp expects to reduce its work force company-wide by approximately 1,600 over a five year period ending in 2005, mainly through early retirement, voluntary severance and attrition.

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Approximately 60% of the employees of PacifiCorp and its mining affiliates are covered by union contracts, principally with the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Boilermakers and the United Mine Workers of America. In the company’s judgement, employee relations in the US businesses are satisfactory.

UK businesses

ScottishPower and its continuing UK subsidiaries had 7,666 employees, as at 31 March 2002, of these, 4,582 were employed in the UK Division and 3,084 in the Infrastructure Division. Approximately 60% of employees in the UK are union members, and over 80% are covered by collective bargaining arrangements. There are a number of different collective agreements in place throughout the group, reflecting differing market conditions in which the group’s businesses operate. Although there was a brief industrial dispute (now resolved) within the Power Systems business unit during the period of its restructuring, the company judges employee relations in the UK businesses to be satisfactory.

Group environmental policy

ScottishPower aims to be a responsible company, balancing its business goal of creating sustainable value with wide-ranging but differing stakeholder opinions on which environmental issues are particularly crucial. Nonetheless, climate change has emerged as a dominant sustainability challenge for all businesses, and is particularly acute for the energy sector. In the UK, policies to combat global climate change are paramount, with fiscal and regulatory incentives deployed with the aim of achieving a UK target of a 20% reduction in carbon dioxide (“CO2”) emissions by 2010. The US remains concerned about global climate change and has proposed measures to bring CO2 emissions under control. Similarly, both the US and the UK aim to reduce emissions to air from fossil-fired generation, with tighter controls on air pollution proposed in the Clear Skies Initiative and driven by continued implementation of the US Clean Air Act and, in the UK, by regulations such as the European Union (“EU”) Ceilings Directive, the Large Combustion Plants Directive (“LCPD”) and the Directive on Integrated Pollution Prevention and Control. In the US, issues of biodiversity and conservation are more prominent than in the UK, with the impact of hydro dams on migratory fish runs being of broad concern to western stakeholders. ScottishPower has responded to these policy drivers and market forces by developing an international vision which focuses on investing heavily in renewables (in particular, wind generation), reducing both the CO2 output and clean air impact of its generation plants and working with customers to implement energy efficiency programmes.

ScottishPower’s vision and framework for action involve achieving lower levels of CO2/GWh across the generation portfolio to combat global climate change, backed up by a range of measures to achieve this overarching goal. Additionally, the company aims to contain the environmental impact of its activities to a practicable minimum and to work with customers and other stakeholders to promote the efficient use of energy and of essential resources. Demanding aspirational targets have been set in both the US and the UK to drive the achievement of this vision and a range of specific initiatives and investments with measurable outcomes, aimed at improving group environmental performance, has been implemented. All ScottishPower businesses are required to implement an environmental management system equivalent to ISO 14001, in order to develop management controls appropriate to the level of risk faced by any particular business area. Some of those systems are certified to the international standard ISO 14001 or, in Europe, registered as compliant with the EU’s Eco-Management and Audit Scheme.

The Safety and Environmental Management Rating Agency (“SERM”) operates an industry benchmarking scheme which uses a mathematical model to assess the cost of potential incidents and a company’s measures for risk reduction. The results of this exercise are presented in a similar format to a credit rating. ScottishPower’s SERM rating is AA-, where AAA+ is the highest possible and C– is the lowest. ScottishPower has a robust process of environmental risk assessment operating comprehensively across the business and subject to internal review and external scrutiny. The most recent external review was conducted by the respected consultancy firm, OXERA, and concluded that the company had an excellent knowledge of environmental risk and managed such risks with a high level of care and prudence.

Research and development

ScottishPower supports research into development of the generation, transmission, distribution and supply of electricity. It also continues to contribute, on an industry-wide basis, towards the cost of research into electricity utilisation and distribution developments. In financial years 2001/02, 2000/01 and 1999/2000, expenditure on research and development in the group businesses was £3.1 million, £4.2 million and £5.5 million, respectively.

Charitable donations

During 2001/02, donations made for charitable purposes by ScottishPower companies totalled £3.5 million. In addition, some £6.0 million of community support activity comprising community investment and commercial initiatives given in cash, through staff time and in-kind donations was undertaken by the company’s US and UK operations.

Description of the company’s property

US business

The US properties consist of generating stations, electricity transmission and distribution facilities, coal mines and a number of non-operational office and service centre facilities. Substantially all of PacifiCorp’s electricity plants are subject to the lien of PacifiCorp’s Mortgage and Deed of Trust.

PacifiCorp owns or has an interest in 53 hydro-electricity plants having an aggregate nameplate rating of 1,068 MW and plant net capability of 1,119 MW. It also owns or has interests in 17 thermal-electricity generating plants with an aggregate nameplate rating of 7,169 MW and plant net capability of 6,663 MW. PacifiCorp also jointly owns one wind power generating plant with an aggregate nameplate rating and plant net capability of 33 MW. Table 1 (page 27) sets out key aspects of PacifiCorp’s existing generating facilities. These generating

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facilities are interconnected through PacifiCorp’s own transmission lines or by contract through the lines of others. Substantially all generating facilities and reservoirs located within the western states region are managed on a coordinated basis to obtain maximum load carrying capability and efficiency. Portions of PacifiCorp’s transmission and distribution systems are located, by franchise or permit, upon public lands, roads and streets and, by easement or licence, upon the lands of other third parties.

PacifiCorp’s coal reserves are described in Table 2 (page 28). Most are held pursuant to leases from the federal government through the Bureau of Land Management and from certain states and private parties. The leases generally have multi-year terms that may be renewed or extended and require payment of rentals and royalties. In addition, federal and state regulations require that comprehensive environmental protection and reclamation standards be met during the course of mining operations and upon completion of mining activities.

PPM owns the entire output from the 263 MW Stateline windfarm and has access to 237 MW from the Klamath co-generation plant.

UK business

The UK properties consist of generating stations, transmission and distribution facilities and certain non-operational properties in which the company holds freehold or leasehold interests.

ScottishPower owns seven power stations in Scotland, two (at Methil and Inverkip) are non-operational, and two in England. It also owns three windfarms in Northern Ireland, four in Scotland, and one in the Republic of Ireland. In addition, the company has joint venture interests in one power station in England and three windfarms, two of which are in England and one in Wales. All generation plant is owned by the group, with the exception of the Methil power station, which is held on a ground lease that expires in 2012 and the windfarms which are generally held on ground leases of at least 25 years’ duration. See Table 7 (page 29) for further details of operational generation assets.

As at 31 March 2002, the UK transmission facilities included approximately 3,900 circuit km of overhead lines and 250 circuit km of underground cable operated at 400 kV, 275 kV and 132 kV. In addition, the distribution facilities included approximately 24,500 circuit km of overhead lines and 41,000 circuit km of underground cable at voltages operating from 33 kV to 0.23 kV in Scotland and approximately 21,500 km of overhead lines and 24,000 km of underground cable at voltages operating from 132 kV to 0.23 kV in England & Wales. The group holds either permanent rights or wayleaves which entitle it to run these lines and cables through private land. See Table 8 (page 29) for further details.

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BUSINESS REVIEW—DESCRIPTION OF LEGISLATIVE AND REGULATORY BACKGROUND

As a public limited company (“plc”), Scottish Power plc is subject to the UK Companies Acts and is also registered as a holding company under the US federal Public Utility Holding Company Act of 1935, as amended (“1935 Act”) which is administered by the US federal Securities and Exchange Commission (“SEC”). Hence, Scottish Power plc, PacifiCorp and other subsidiaries are subject to regulation unless specific subsidiaries or transactions are otherwise exempt by SEC rules or orders. Scottish Power UK plc and its subsidiaries are exempt because Scottish Power UK plc is an exempt foreign utility as defined in Section 33 of the 1935 Act. Whereas US state regulatory commissions generally have jurisdiction over mergers, acquisitions and the sale of utility assets, the UK government, as a way to maintain control over ScottishPower and certain of its subsidiaries, required the issuance of a “Special Share”. The Special Share only affects the corporate control transactions at the overall group holding company level and has no effect on PacifiCorp.

ScottishPower’s UK operations are subject to such EU Directives as the UK Government brings into effect, specifically the EU (energy) Liberalisation Directive and EU prohibitions on anti-competitive agreements and the abuse of a dominant position (implemented through the Competition Act 1998 (“Competition Act”), which came into effect from 1 March 2000). They are also subject to the provisions of the Utilities Act 2000 (“Utilities Act”). The Utilities Act introduced a legal framework for energy company licences based on standard, UK-wide conditions and, taken together with requirements of the DTI and licence changes introduced by the Regulators, has obliged the group to restructure its UK operations into a series of separate limited companies, each a wholly-owned subsidiary of Scottish Power UK plc. This process was implemented in line with a DTI timetable and completed by March 2002.

A summary of the more specific legislative and regulatory background to the operations of the group’s businesses is set out below.

US business regulation

PacifiCorp is subject to the jurisdiction of the public utility regulatory commissions of each of the states in which it conducts retail electricity operations as to prices, services, accounting, issuance of securities and other matters. Commissioners are appointed by the individual state’s governor for varying terms. PacifiCorp is a “licensee” and a “public utility” as those terms are used in the Federal Power Act (“FPA”) and is, therefore, subject to regulation by the Federal Energy Regulatory Commission (“FERC”) as to accounting policies and practices, certain prices and other matters.

Proposed restructuring

PacifiCorp has initiated a collaborative process with the six states it serves to investigate the challenges faced by the Company as a multi-state utility. Through this Multi-State Process (“MSP”), the participants are working to clarify roles and responsibilities including cost allocations for future generation resources, provide states with the ability to independently implement state energy policy objectives, and achieve permanent consensus on each state’s responsibility for the costs and entitlement to the benefits of PacifiCorp’s existing assets. MSP was initiated to develop and review possible solutions, including PacifiCorp’s Structural Realignment Proposal (“SRP”). SRP was filed in December 2000 and would realign PacifiCorp to create six state electricity companies, a generation company and a service company. Individual state proceedings and schedules for SRP will be ‘on-hold’ so long as reasonable progress is made through the MSP.

Regional Transmission Organization (“RTO”)

PacifiCorp is one of 10 parties involved in an effort to form an RTO, named RTO West, in support of FERC Order 2000. The 10 members of RTO West will be Avista Corporation, British Columbia Hydro Power Authority, Bonneville Power Administration, Idaho Power Company, Northwestern Energy L.L.C (formerly Montana Power Company), Nevada Power Company, PacifiCorp, Portland General Electric Company, Puget Sound Energy, Inc. and Sierra Pacific Power Company. Creation of RTO West is subject to regulatory approvals from FERC and the states served by these entities. RTO West plans to operate all transmission facilities needed for bulk power transfers and control the majority of the 60,000 miles of transmission line owned by the parties. On 29 March 2002, the members filed a request with the FERC for a declaratory judgement that their proposals satisfy the characteristics and functions of FERC Order 2000; a ruling is expected by August 2002.

Relicensing of hydro-electric projects

        PacifiCorp’s hydro-electric portfolio consists of 53 plants with a total capacity of approximately 1,100 MW. Of the installed capacity, 97% is regulated by the FERC through 20 individual licences. These projects account for about 14% of PacifiCorp’s total generating capacity and provide operational benefits such as peaking capacity, generation, spinning reserves and voltage control. Nearly all of PacifiCorp’s hydro-electric projects are in some stage of relicensing under the FPA. The relicensing process is a public regulatory process that involves controversial resource issues. In the new licences, the FERC is expected to impose conditions designed to address the impact of the projects on fish and other environmental concerns. In addition, under the FPA and other laws, the state and federal agencies and Native American Tribal Councils have mandatory conditioning authorities that give them significant influence and control in the relicensing process. It is difficult to determine the economic impact of these mandates but capital expenditure and operating costs are expected to increase in future periods, while power losses may result due to environmental and fish concerns. As a result of these issues, PacifiCorp has analysed the costs and benefits of relicensing the Condit dam and has agreed to remove it, subject to FERC approval.

Recovery of deferred net power costs

PacifiCorp is actively pursuing recovery of net power costs greater than the power costs used in setting retail rates. At 31 March 2002, net power costs held in deferred accounts under US GAAP totalled $392 million (including carrying charges) of which filings for recovery had been made to the relevant state commissions for $308 million plus carrying charges.

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Commodity price risk mitigation

PacifiCorp continues to take further steps to manage commodity price volatility and to reduce its exposure, including adding generating capacity and entering into transactions which further hedge demand shape and reduce resource and price risk on hot summer days. “Hydro-electric”, physical and temperature-related hedges are in place to limit commodity volume and price risks and PacifiCorp is working with regulators and other stakeholders on an Integrated Resource Plan intended to identify the least cost and lowest risk approach to securing power over the next 20 to 25 years.

Demand side management

PacifiCorp continues to offer its Energy Exchange programmes in Utah, Oregon, Wyoming, Washington and Idaho. These programmes are optional, supplemental services that allow participating customers an opportunity to reduce electricity usage in exchange for a payment at times and at prices determined by PacifiCorp. The programmes are designed to help all customers of one MW and greater to address high-price and volatile wholesale market circumstances when they occur. Voluntary curtailment programmes for irrigation customers in Utah, Oregon, Washington and Idaho operated for relevant parts of the 2001 calendar year. On 30 September 2001, PacifiCorp also completed its Customer Challenge Program under which residential customers in all six states it serves could secure a 20% credit on monthly bills in June, July, August and September of 2001 by reducing their monthly kWh usage from the corresponding month one year ago by 20%. In Utah, Oregon, Wyoming, Washington and Idaho, PacifiCorp residential customers achieving a 10% reduction compared with the equivalent month in the previous year qualified for a 10% credit to their monthly bills. Evaluation reports were filed with the state commissions in December 2001.

BPA Exchange

The 1980 Pacific Northwest Electric Power Planning and Conservation Act provided for, among other things, the Residential Exchange Program to give the residential and small farm customers of Northwest investor-owned utilities a share of the benefits associated with the federal Columbia River Power System. The Residential Exchange Program expired on 30 September 2001. Replacement agreements executed on 30 October 2000 and 23 May 2001 between PacifiCorp and the BPA and effective from 1 October 2001 are expected to provide PacifiCorp’s residential and irrigation customers in Oregon, Washington and Idaho with annual benefits equalling $115 million in year one and $119 million a year for years two to five. These benefits pass through to customers and do not affect PacifiCorp’s earnings.

A summary of the outcomes and the most significant further regulatory and legislative developments in the states concerned is set out below.

Utah

On 12 January 2001, PacifiCorp filed a request with the Utah Public Service Commission (“UPSC”) for an increase in electricity prices for its customers in Utah. Concurrently, PacifiCorp filed a separate emergency petition for interim relief in respect of power cost variances associated with the outage caused by the failure of a 430 MW generation unit at PacifiCorp’s Hunter power plant in Utah. An interim increase was granted in February 2001 and, on 1 May 2002, the UPSC issued an order approving an agreement regarding the recovery of deferred net power costs in Utah. The order allows for the consolidation of a number of individual issues into an overall programme under which PacifiCorp will recover a total of $147 million of deferred power costs and commit not to file a general rate case that would take effect prior to 1 January 2004, except in certain exceptional circumstances.

PacifiCorp’s previously approved application for deferred accounting treatment of unrecovered investment associated with the closed Trail Mountain coal mine was amended, on 10 July 2001, from $27 million to $46 million, to include estimated mine closure costs. On 4 April 2002, the UPSC approved deferral of its share of the $46 million, which is to be amortised over five years from 1 April 2002.

Oregon

New rates, which took effect on 1 July 2001 through an annual adjustment as part of the alternative form of regulation (“AFOR”) process previously authorised in Oregon, increased annual revenues by approximately $7.6 million and will run until PacifiCorp recovers all earnings allowed under the AFOR, estimated to be by June 2002. On 7 September 2001, the Oregon Public Utility Commission (“OPUC”) granted a rate increase of $64.4 million, effective from 10 September 2001, reflecting the increased costs of operations. Senate Bill 1149, which was enacted in 1999, provides direct access for industrial and large commercial customers of both PacifiCorp and Portland General Electric Company and offers to residential and small commercial customers a portfolio of rate options that includes new renewable energy resources and market-based pricing. Enactment of subsequent legislation in 2001 delayed implementation of SB 1149 to 1 March 2002 and required PacifiCorp and Portland General Electric Company to provide all customers with a cost-of-service rate option for an indefinite period. Beginning 1 July 2003, the OPUC may waive the cost-of-service rate option for classes of customers if it finds that retail markets are functioning properly. PacifiCorp is now recovering the approximately $18 million additional costs arising from SB 1149 implementation over a five year period.

The final order in the rate case that concluded in September 2001 required PacifiCorp to file the results of a new hourly net cost model. The new model was filed on 31 December 2001 as part of a power cost rate case requesting a $34.3 million annual rate increase and a permanent power cost adjustment mechanism. All parties filed a stipulation on 29 March 2002 providing for a variety of permanent and temporary rate increases and decreases resulting from changes in net power costs, the sale of PacifiCorp’s Hermiston service territory and Trail Mountain mine closure costs. These changes total an overall first-year increase of $14.2 million. A final order in the power cost rate case is expected to be issued by June 2002.

Deferred accounting filings encompassing power costs that varied from the levels in Oregon rates are the subject of continuing hearings, although partial recovery of the deferred costs is continuing under a 3% ($23 million a year) rate increase effective

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from 21 February 2001 and now extended to June 2002. In December 2001, PacifiCorp reached an agreement with OPUC staff under which the recovery of $130 million of deferred net power costs would be allowed. Final orders arising from the various deferred power cost hearings are expected in May and June 2002.

Wyoming

In April 2001, the Wyoming Public Service Commission (“WPSC”) approved deferred accounting treatment of the State’s share of the unrecovered investment associated with the Trail Mountain coal mine closure. On 9 July 2001, PacifiCorp received an order from the WPSC approving the all-party stipulation settling all issues in the December 2000 rate case. The order resulted in increased annual revenues of $8.9 million, effective from 1 August 2001. A $121 million general rate case, including the excess net power costs for which recovery was being sought in earlier proceedings now withdrawn without prejudice, will be filed on 7 May 2002.

Washington

On 9 August 2000, PacifiCorp received an order from the Washington Utilities & Transportation Commission which authorised PacifiCorp to increase rates by 3% on 1 September 2000, 3% on 1 January 2002 and 1% on 1 January 2003.

PacifiCorp filed on 5 April 2002 for approval to begin deferred accounting for excess power costs. Deferred account amounts in Washington are estimated at up to $12 million. Under the proposal, PacifiCorp would track costs beginning 1 June 2002 for one year or until a power cost adjustment mechanism is implemented in the state. If the deferred accounting proposal is approved, PacifiCorp plans to propose a recovery mechanism before October 2002.

Idaho

On 7 January 2002, PacifiCorp filed a request with the Idaho Public Utilities Commission (“IPUC”) to recover $38 million of deferred excess power costs through a temporary 24-month surcharge and to implement a new credit to pass through the benefits from the two BPA settlement agreements. On 10 April 2002 parties reached agreement on a $25 million stipulation on power costs which will, if subsequently approved by the IPUC, be recovered through a two-year surcharge on Utah Power customer bills in Idaho and the elimination of merger credit obligations.

California

An order for PacifiCorp’s 16 March 2001 request for immediate interim rate relief has been routed for review by the assigned administrative law judge (“ALJ”) and should be voted upon by the California Public Utilities Commission in the near future. This request, if granted in terms of the proposed order, would provide approximately $4.9 million in annual rate relief and would be subject to refund pending the outcome of a general rate case.

On 21 December 2001, the company filed a general rate case requesting a $16 million, or 29.4%, annual general rate increase, which incorporates the interim rate relief request. Both the California staff and PacifiCorp have filed motions regarding the litigation of the case, however at this time no decision has been made by the assigned ALJ to move forward with a review.

Regulation of the electricity and gas industries in the UK

The UK electricity and gas industries are regulated under the provisions of the Electricity Act, the Gas Acts and the Utilities Act. The Electricity and Gas Acts provided for the privatisation and restructuring of the industries in the late 1980s and the 1990s, including the introduction of price regulation for electricity transmission and distribution and gas transportation; and of competition in electricity generation, gas storage and the supply of both gas and electricity. The Acts established the licensing of industry participants and created regulatory bodies for each of the electricity and gas industries. In 2000, the Utilities Act enabled the electricity and gas regulators to be merged as the Gas and Electricity Markets Authority (“the Authority”), established new independent consumer councils and provided powers for Government Ministers to give statutory guidance on social and environmental issues and to set energy efficiency targets and renewables obligations.

        The Utilities Act transferred the functions of the previous electricity and gas industry regulators to the Authority and provided for the appointment of a Chairman and other members of the Authority by the Secretary of State for Trade and Industry (“Secretary of State”). The Chairman of the Authority holds office for renewable periods of five years and is the Managing Director of the Office of Gas and Electricity Markets (“Ofgem”) which provides administrative support to the Authority. Under the Utilities Act, the principal objective of the Secretary of State and the Authority is to protect the interest of customers, wherever appropriate by promoting effective competition. In carrying out those functions, they are required to have regard to the need to secure that all reasonable demands for electricity and gas are met; the need to ensure that licence holders are able to finance their functions; the interests of individuals who are disabled or chronically sick, of pensionable age, with low incomes or residing in rural areas. The Authority exercises, concurrently with the Director General of Fair Trading, certain functions relating to monopoly situations under the Fair Trading Act 1973 and to anti-competitive conduct under the Competition Act 1980 and the Competition Act 1998. The Authority also manages UK compliance with the European Community Liberalisation Directive, which is concerned to introduce competition in generation and supply and non-discriminatory access to gas transportation and electricity transmission and distribution across the EU.

The licensing regime

The Authority is responsible for granting new licences or licence extensions for each of the following separate activities:

Electricity generation—the production of electricity at power stations, hydro-electric plants, windfarms and some industrial plants. Through its wholly-owned subsidiary, Scottish Power Generation Limited, the group is licensed to operate some 5,300 MW of UK generating capacity, see Table 7 (page 29) and, by contracting in the wholesale market, has access to capacity operated by other licensed generators.

Electricity transmission—the bulk transfer of electricity across a high voltage network of overhead lines, underground cables and

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associated equipment typically operating at or above 132 kV. Through its wholly-owned subsidiary, SP Transmission Limited, the group owns and is licensed to operate the transmission system in central and southern Scotland. ScottishPower’s transmission system is connected to that of Scottish & Southern Energy in the north of Scotland and is linked to the National Grid in England & Wales and to the Northern Ireland transmission system by interconnectors which enable the export and import of electricity within the UK. The Authority is currently conducting a review of transmission arrangements (BETTA) which envisages a Great Britain-wide wholesale market for electricity and revised arrangements in respect of the interconnector between England and Scotland. It is anticipated that new arrangements will require primary legislation and development work is underway aimed at implementation in 2004.

Electricity distribution—the transfer of electricity from the high voltage transmission system and its delivery to customers, across a network of overhead lines and underground cables operating at voltages ranging from 33 kV to 0.23 kV. The Utilities Act required separate licensing of the 14 regional distribution businesses introduced under electricity privatisation. Each Public Electricity Distributor (“PED”) licensee is required, among other duties, to develop and maintain an efficient, coordinated and economical system of electricity distribution and to offer terms for connection to, and use of, its distribution system on a non-discriminatory basis, in order to ensure competition in the supply and generation of electricity. Through its wholly-owned subsidiaries, SP Distribution Limited and SP Manweb plc, the group is licensed to distribute electricity within its two distribution services areas for all suppliers whose customers are within the areas. Charges for distribution are made to the various suppliers as appropriate. The Authority has granted a derogation, which will lapse only in certain limited circumstances, allowing the distribution businesses in the ScottishPower and Manweb PED distribution services areas to be managed and operated jointly.

Gas transportation and storage—the onshore transportation system, most of which is owned and operated by Transco, the transportation arm of Lattice plc, and the rest by other gas transporters, conveys gas from the beach terminals to consumers and is interconnected with the gas transportation systems of continental Europe, Northern Ireland and the Republic of Ireland. Storage capacities are largely used to balance supply and demand over time. Major facilities are used to balance seasonal variations in demand while diurnal storage capacities provide flexibility in meeting changing gas demand on a daily basis. Competition in storage has been introduced progressively since 1998 through the auction of major storage capacity owned by Transco and the provision of new capacity by independent operators, including ScottishPower. Through its wholly-owned subsidiary, SP Gas Limited, the group is licensed as a gas transporter.

Gas shipping—gas shippers contract with gas transporters to have gas transported between the beach terminal and the point of supply. Gas shippers can also access storage facilities. The group is licensed as a gas shipper.

Supply of gas and electricity—the bulk purchase of gas and electricity by suppliers and its sale to customers, with the associated customer service activities, including customer registration, meter reading, sales and marketing, billing and revenue collection. Large industrial and commercial customers have been able to choose their energy suppliers for a number of years and the residential market was opened to competition progressively, commencing in April 1996, with residual controls on residential electricity prices ending in March 2002. Any electricity supplier wishing to supply electricity to domestic customers must obtain authorisation from the Authority and be subject to additional domestic supply obligations in its licence, including having its codes of practice (statements of intent about how the supplier will interact with customers) approved by the Authority. Broadly comparable arrangements allow British Gas Trading to supply mains gas to any connected customer in competition with licensed gas suppliers. Customers may continue to take supplies from the pre-privatisation monopoly supplier for the area or may choose an alternative licensed supplier. Once customers have changed a gas or electricity supplier, they are able to change supplier again subject to the contractual terms offered by licensed suppliers and approved by the Authority. Through its wholly-owned subsidiary, ScottishPower Energy Retail Limited, the group is licensed as a gas supplier and an electricity supplier.

        Modification of licences—The Authority is responsible for monitoring compliance with the conditions of licences and, where necessary, enforcing them through procedures laid down in the Electricity and Gas Acts. Under these Acts, as amended by the Utilities Act, licences consist of standard licence conditions, which apply to all classes of licences, and special conditions particular to that licence. The Authority may modify standard licence conditions collectively through making proposals to all relevant licence holders. If some licence holders object, the modification may be carried out only if the number of objectors is below a specified minority. The Authority may modify a special licence condition with the agreement of the licence holder after due notice, public consultation, and consideration of any representations or objections. In the absence of agreement for a special licence condition or if objections are above the specified minority threshold for a standard licence condition, the only means by which the Authority can secure a modification is following a modification reference to the Competition Commission and in the circumstances set out below. A modification reference requires the Competition Commission to investigate (having regard to the matters in relation to which duties are imposed on the Secretary of State and the Authority) and report on whether matters specified in the reference in pursuance of a licence operate, or may be expected to operate, against the public interest; and, if so, whether the adverse public interest effect of these factors could be remedied or prevented by modification of the conditions of the licence. If the Competition Commission so concludes, the Authority must then make such modifications to the licence as appear to it requisite for the purpose of remedying or preventing the adverse effects specified in the report, after giving due notice and consideration to any representations and

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objections. The Secretary of State has the power to veto any modification.

Modifications to licence conditions may also be made in consequence of a monopoly or merger reference under the Fair Trading Act 1973 or a reference under the Competition Act. ScottishPower’s acquisition of Manweb in 1995 and of Southern Water in 1996 and its merger with PacifiCorp in 1999 all involved ScottishPower giving undertakings to the Secretary of State to agree to modifications to the licences under which the group operates in the UK (and to Southern Water Services’ Water Appointment). Broadly, these modifications were designed to ring-fence various UK regulated businesses, to require that the group had sufficient management and financial resources to fulfil its UK obligations and to ensure that UK regulators would continue to have access to the information needed to carry out their duties.

Term and revocation of licences—Licences under the Electricity Act, as modified by the Utilities Act, may be terminated by not less than 25 years’ notice given by the Secretary of State and may be revoked in certain circumstances specified in the licence. These include the insolvency of the licensee, the licensee’s failure to comply with an enforcement order made by the Authority and the licensee’s failure to carry on the activities authorised by the licence.

Price controls

The primary objective of the regulation of the UK gas and electricity industry is the promotion of competition, while ensuring that demand can be met and companies are able to finance their regulated activities. However, it is recognised that the development of competitive markets is not appropriate in some areas: the transmission and distribution of electricity and the operation of the gas transportation system. In these areas, regulatory controls are deemed necessary to protect customers in monopoly markets (by determining inflation-limited price caps) and to encourage efficiency. The group’s UK wires businesses are subject to price controls (or revenue controls in the case of the transmission business) which restrict the average amount, or total amount, charged for a bundle of services. The price caps are expressed in terms of an “RPI—X” constraint on charges, where “RPI” represents the annual percentage change in the UK’s retail price index, and X may be any number determined by the Authority. The X factor is used to reflect expected efficiency gains and investment requirements. For example, where RPI is running at 3% and X is 2%, a company would be able to increase the average charge for a bundle of services by 1% per annum. The Authority from time to time reviews the price cap formulae. Through participation in, and the submission of evidence to, these price control reviews and, where necessary, through the Competition Commission modification process described above, companies have the opportunity to comment on and seek to influence the final outcome of any price control review.

Transmission price control—The revised transmission price control for ScottishPower, which took effect for the five years from 1 April 2000, is subject to the BETTA review, which envisages a Great Britain-wide wholesale market for electricity and revised arrangements in respect of the interconnector between Scotland and England. This is likely to involve the inclusion of the present interconnector circuits into the relevant price controlled transmission asset bases and the application of harmonised transmission access principles across Great Britain. It is anticipated that new arrangements will require primary legislation and development work is underway aimed at implementation in 2004.

Distribution price control—The maximum distribution revenue is calculated from a formula that is based on customer numbers as well as units distributed. Distribution price controls for the ScottishPower and Manweb areas, which took effect for the five years from 1 April 2000, have been subject to a review by the Authority aimed at ensuring that revenues and outputs of the business are more closely matched and meet customers’ expectations. This has involved an examination of the appropriate information and incentives and has led to a refinement of the price controls to place less emphasis on periodic reviews and more emphasis on continuous performance. Following completion of the review, in April 2002, companies’ future revenues can be adjusted by up to 2% to reflect better or worse than target performance.

Environmental regulation

Throughout its operations, ScottishPower aims to meet, or better, relevant legislative and regulatory environmental requirements and codes of practice. ScottishPower will publish its 2002 Environmental Sustainability Report in July 2002. Copies will be available on request from the Company Secretary.

US environmental regulation

Federal, state and local authorities regulate many of PacifiCorp’s activities pursuant to laws designed to protect, restore and enhance the quality of the environment. These laws have increased the cost of providing electricity service. PacifiCorp is unable to predict what material impact, if any, changes in environmental laws and regulations may have on the group’s consolidated financial position, results of operations, cash flows, liquidity and capital expenditure requirements.

Air quality

        PacifiCorp’s fossil-fuel electricity generating plants are subject to air quality regulation under federal, state and local requirements. Emission controls and trading, low sulphur coal, plant operating practices and continuous emissions monitoring are all used to enable coal-burning plants to comply with emission limits, opacity, visibility and other air quality requirements. The United States Environmental Protection Agency (“EPA”) has implemented regulations addressing regional haze. Carbon dioxide (“CO₂”) emissions are the subject of growing worldwide discussion and action in the context of global warming but such emissions are not currently regulated. The Clear Skies Initiative proposes indicative reductions in relative CO₂ levels and reductions in sulphur dioxide (“SO₂”), oxides of nitrogen (“NO_X”) and mercury emissions, which will be taken into account in the forward development of the PacifiCorp emissions-scrubbing programme. In 1999, the EPA commenced enforcement actions under the New Source Review (“NSR”) against some eastern and mid-western utilities. Fact finding with respect to NSR is proceeding against western utilities, including PacifiCorp. NSR cases could potentially require retro-fitting of SO₂ and NO_X control equipment on some

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PacifiCorp coal-fired plants. PacifiCorp is co-operating with the EPA and is actively considering the implications of the Clear Skies Initiative.

Electric and Magnetic Fields (“EMFs”)

A number of studies continue to examine the possibility of adverse health effects from EMFs, without conclusive results. Certain states and cities have enacted regulations to limit the strength of magnetic fields at the edge of transmission line rights-of-way. Other than in California, none of the state agencies with jurisdiction over PacifiCorp’s operations has adopted formal rules or programmes with respect to magnetic fields or magnetic field considerations in the siting of electricity facilities. The CPUC has issued an interim order requiring power providers to implement no-cost or low-cost mitigation steps in the design of new facilities. It is uncertain whether PacifiCorp’s operations may be adversely affected in other ways as a result of EMF concerns.

Endangered species

Presence of threatened and endangered species (“T&E species”) or protection of their habitat can make it difficult and more costly to perform some of the core activities of PacifiCorp. These include the siting, construction, maintenance and operation of new and existing transmission and distribution facilities and generating plants. In addition, T&E species issues and compliance with the Endangered Species Act (“ESA”) impact the relicensing of existing hydro-electric generating projects, resulting in costly mitigation. Mitigation costs generally raise the price PacifiCorp must pay to purchase wholesale power from hydro-electric facilities owned by others and increases the costs of operating PacifiCorp’s own hydro-electric resources. Compliance with the ESA could also result in further restrictions on land uses, including timber harvesting, and adversely affect electricity sales to PacifiCorp’s customers in the wood products industry.

Environmental clean-ups

Under the Federal Comprehensive Environmental Response, Compensation and Liability Act and similar state statutes, entities that accidentally or intentionally disposed of, or arranged for the disposal of, hazardous substances may be liable for clean-up of the contaminated property. In addition, the current or former owners or operators of affected sites also may be liable. PacifiCorp has been identified as a potentially responsible party in connection with a number of clean-up sites because of current or past ownership or operation of the property or because PacifiCorp sent hazardous waste or other hazardous substances to the property in the past. PacifiCorp has completed several clean-up actions and is actively participating in investigations and remedial actions at other sites. The costs associated with those actions are not expected to be material to the group’s consolidated financial position, results of operations, cash flows, liquidity or capital expenditure requirements.

Mining

All of PacifiCorp’s mining operations are subject to reclamation and closure requirements. Compliance with these requirements could result in higher expenditures for both capital improvements and operating costs.

Water quality

The Federal Clean Water Act and individual state clean water regulations require a permit for the discharge of wastewater, including storm water run off from the power plants and coal storage areas, into surface waters. Also, permits may be required in some cases for discharges into ground waters. PacifiCorp believes that it currently has all required permits and management systems in place to assure compliance with permit requirements, except that additional permits are required in connection with the relicensing of hydroelectric facilities (see page 18).

UK environmental regulation

        The group’s UK businesses are subject to numerous regulatory requirements with respect to the protection of the environment, including environmental laws which regulate the construction, operation and decommissioning of power stations, pursuant to legislation implementing environmental directives adopted by the EU and protocols agreed under the auspices of international bodies such as the United Nations Economic Commission for Europe (“UNECE”). The group believes that it has taken and continues to take measures to comply with applicable laws and regulations for the protection of the environment. Applicable regulations and requirements pertaining to the environment change frequently, however, with the result that continued compliance may require material investments or that the group’s costs and results of operation are less favourable than anticipated.

Electricity generation, transmission, distribution and supply

        The Electricity Act obligates the Secretary of State to take into account the effect of electricity generation, transmission and supply activities upon the physical environment in approving applications for the construction of generating facilities and the location of overhead power lines. The Electricity Act requires the group to take into account the conservation of natural features of beauty and other items of particular interest and, in terms of the Environmental Impact Assessment Regulations, to carry out an environmental assessment when it intends to construct significant overhead transmission systems or power stations of greater capacity than 50 MW. The group also prepares formal statements on the “Preservation of Amenity and Fisheries” in line with the requirements of the Electricity Act.

The Utilities Act provided for environmental guidance to be given by the Secretary of State to the energy regulator, Ofgem, and for regulations to be drawn up which require licensed electricity suppliers to secure a certain percentage of their supplies from renewable energy sources, compliance being demonstrated by tradable ‘Renewable Obligation Certificates’. The current objective is that 10% of UK energy should come from renewable sources by 2010 and it is anticipated that, in the forthcoming government review of energy policy, this obligation could rise to 20% of supplies in the UK by 2020. ScottishPower continues to develop its windfarm business and expects to meet the company target of 10% generation from renewables by 2010. The Utilities Act also provided for energy efficiency targets to be set for licensed suppliers to be implemented by an “Energy Efficiency Commitment” and the emphasis on energy saving in the recent Cabinet Office report suggests that this may be further reinforced in the Energy White Paper scheduled for late-2002.

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The Environmental Protection Act of 1990 (“EPA 1990”) requires that potentially polluting activities such as the operation of combustion processes (which includes power plant) obtain prior authorisation. The Act also provides for the licensing of waste management and imposes certain obligations and duties on companies which produce, handle and dispose of waste. Waste generated as a result of the group’s electricity activities is managed to ensure compliance with legislation and waste minimisation is undertaken where possible.

Possible adverse health effects of EMFs from various sources, including transmission and distribution lines, have been the subject of a number of studies and increasing public discussion. The UK Childhood Cancer Study—the world’s largest study ever of its kind—found no evidence that EMFs do cause cancer. Evidence from other research, such as laboratory studies, also argues against any link but, because of the conclusions of other smaller studies from around the world, scientists cannot totally dismiss the possibility of a small risk to the very few children who receive the highest exposure to magnetic fields. However, the March 2001 National Radiological Protection Board review concluded that the epidemiological evidence does not support the conclusion that exposure to magnetic fields causes leukaemia.

Generation activities

The principal emissions from fossil-fuelled electricity generation are SO₂, NOx, CO₂ and particulate matter, such as dust, with the main waste being ash, namely pulverised fuel ash and furnace bottom ash. The primary focus of current environmental legislation is to reduce emissions of SO₂, NO_X and particulates, the first two of which contribute to acid rain. A number of other power station emissions and discharges are subject to environmental regulation.

The EU has, under the terms of the Kyoto Protocol, signed up to the United Nations Framework Convention on Climate Change, under which Member States are committed to reducing “greenhouse gases” by 8% below 1990 emission levels between the years 2008 and 2012. The UK Government has announced its goal of a 20% reduction in CO₂ emissions by 2010, largely driven by its “Climate Change Programme” which sets in place a range of policy instruments aimed at delivery of the 20% reduction target. These include targets for renewable energy, targets for combined heat and power, a Climate Change Levy charged on industrial and commercial energy usage and residential energy efficiency measures. Obligations put in place under the Utilities Act play an important part in the Programme.

EPA 1990 is the primary UK statute governing the environmental regulation of power stations. In April 1991, it introduced a system of Integrated Pollution Control (“IPC”) for large-scale industrial processes, including power stations, now enforced with respect to emissions to the atmosphere in England & Wales by the Environment Agency (“EA”) and in Scotland by the Scottish Environment Protection Agency (“SEPA”). Each of ScottishPower’s power stations is required to have its own IPC authorisation, issued by the EA or SEPA, regulating emissions of certain pollutants, seeking to minimise pollution of the environment and containing an improvement programme. Each IPC authorisation required that a power station uses the Best Available Techniques Not Entailing Excessive Cost (“BATNEEC”) to prevent the emissions described above or, to the extent this is not practicable, to minimise and render harmless any such emissions. ScottishPower’s IPC authorisations do not have an expiry date, but the EA or SEPA is required to review the conditions contained within them at least once every four years and may impose new conditions to prevent or reduce emissions of pollutants, subject to the application of BATNEEC.

The EU has agreed a Directive on Integrated Pollution Prevention and Control, which introduces a system of licensing for industrial processes such as power stations. This Directive is being implemented via the Pollution Prevention and Control Regulations (“PPC Regulations”) which is bringing modifications to the IPC regime into effect, on a staged basis. The EU Directive will eventually require that all emission and pollution control measures are placed onto a “Best Available Techniques” basis to control impact on the environment.

        The EU has adopted a framework directive on ambient air quality assessment and management, which is being implemented in the UK by means of the National Air Quality Strategy published in 1997 and reviewed in 2000. Under the auspices of UNECE, protocols regarding reductions in the emissions of SO₂ and NO_X have been agreed. These are currently implemented in the EU by means of the LCPD. The EU has agreed a “Ceilings Directive” which will implement the SO₂ and NO_X targets agreed in the UNECE Gothenburg Protocol. The LCPD has been reviewed and will bring into place a new control framework. The government intends to consult on UK implementation during the summer of 2002. Controls on emissions from existing and new plants will be introduced via the new provisions, the Air Framework Directive and, in the future, the PPC Regulations. The group has identified options that, given the appropriate commercial conditions, would enable it to continue to meet the environmental improvements required by potential future limits arising from this review, without materially constraining operational and commercial flexibility. In particular, gas-reburn technology, as used at Longannet, offers greater potential to reduce emissions than other technology in use elsewhere in the UK.

Contaminated sites

        While the nature of developments in environmental regulation and control cannot be predicted, the group anticipates that the direction of future changes will be towards tightening controls. In view of the age and history of many sites owned by the group, the group may incur liability in respect of sites which are found to be contaminated, together with increased costs of managing or cleaning up such sites. Site values could be affected and potential liability and clean-up costs may make disposal of potentially contaminated sites more difficult. The Contaminated Land Regulations, which implement provisions of the Environment Act 1995 (“EA 1995”), require local authorities to identify sites where significant harm is being caused and to take appropriate steps. In order for harm to be demonstrated, it must be shown that a source of pollution, a receptor and a

24

pathway are present. Harm may be eliminated by clean-up or by breaking the source to receptor pathway. Clean-up is only required to “fit for subsequent use” standards, so that environmental compliance is consistent with the intended use of the site.

Other proposals which may impose strict liability for environmental damage are also under consideration by the EU and a draft directive may be brought forward. ScottishPower is not currently aware of any liability which it may have under EA1995 or proposed EU directives which will have a materially adverse impact on its operations.

Employment regulation

Equal opportunity

    US businesses

Both PacifiCorp and PPM have equal employment and harassment policies which reflect their belief that they can best achieve their objectives by effectively utilising the skills and abilities of a diverse workforce. The US has extensive anti-discrimination legislation enacted at federal, state and local levels which prohibits discrimination in employment for a variety of reasons including age, race, colour, sex, religion, creed, sexual orientation, national origin, physical or mental disability. As part of its equal employment opportunity policy, PacifiCorp has implemented and maintains a programme of “affirmative action” in order to effectively employ minorities and women in the workforce and to encourage workforce diversity. This programme also covers Vietnam veterans and disabled persons/veterans. The programme also provides an effective means of complying with the periodic compliance reviews conducted by the United States Department of Labor. PacifiCorp has long recognised its responsibility to assist community action services. An integral part of the company’s Affirmative Action Program is participation in organisations which are active in workforce and economic development within communities served by PacifiCorp.

    UK businesses

It is ScottishPower’s policy to promote equality of opportunity in recruitment, employment continuity, training and career development. To support the Policy Statement on Equal Opportunities, specific policies have been introduced on people with disabilities, on sex and race discrimination, and on harassment. In addition, a number of family friendly policies have been introduced including a caring break, enhanced maternity leave, paternity leave and leave for adoption or fertility treatment. ScottishPower is a Gold Card Member of the Employers’ Forum on Disability and also a member of the Employers’ Forum on Age, and the Equal Opportunities Commission Equality Exchange. The company is also in the process of gaining accreditation for Tommy’s Pregnancy Programme and the Two Tick Disability Symbol. As part of the ongoing development and implementation of its equal opportunities strategy, the group has designed and implemented an Equality Framework, which is used to audit and undertake action plans on an annual basis. Actions arising from these plans are discussed in the Company Equality Forum.

Health and safety

    Corporate Responsibility

ScottishPower constantly strives to work to the highest levels of occupational safety across its international business and to continuously improve health and safety performance. The policy framework developed to drive this process in the UK has been reviewed in relation to US operations, leading to largely harmonised arrangements which recognise the different regulatory and cultural environments in which the group operates. A US safety policy has recently been issued by PacifiCorp’s Executive Safety Committee. This is aligned to ScottishPower’s policy but a number of features are designed for compliance with US law.

        The group’s approach to health and safety governance mirrors the highly commended structures and processes adopted for the direction and control of environmental issues. The governance system being developed in the US will be designed to limit risk under US law but will follow the UK model where this is feasible. It is anticipated that a corporate governance audit of the UK programmes will take place in the financial year 2002/03.

In the UK, most business units have now applied the Quality Safety Audit (“QSA”) technique to their operations. This audit system measures the quality of safety management on a scale from 1 to 5, with 5 being the best. All UK business units have the target of achieving level 5.

The applicability of this technique in the US is being reviewed and, if appropriate, it will be introduced there. Formal audit programmes with close similarities to QSA have been in place for some years in PacifiCorp’s generation and mining businesses.

Further details of the group’s approach to and performance in respect of health and safety matters are contained in the Health & Safety Report for 2001/02 which will be available on the ScottishPower and PacifiCorp websites from August 2002.

    Compliance arrangements

        In the US, companies can be fined and prosecuted under federal and state Occupational Safety and Health Act programmes and by Public Utility Commissions and the Department of Transportation with significant civil fines and possible criminal penalties related to serious health and safety accidents. Fines are the most typical form of punishment for significant non-intentional violations of regulations and laws. Prosecutions related to health and safety matters are much more common in the US than the UK. Most prosecutions are performed under the normal criminal justice system, rather than health and safety laws. These usually involve serious neglect, near the level of gross negligence or knowing failure to comply with rules.

In the US, it is mandatory for the mining regulatory authority, MSHA, to inspect businesses and underground mines at least four times a year and surface mines at least twice a year. Citations are issued by the agency if any of the extensive regulations are violated, with fines issued for all violations which, in the inspector’s opinion, are of a more serious nature. Businesses are subsequently required to correct all violations.

In the UK, there has recently been a

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renewed focus on health and safety with the publication of the landmark “Revitalising Health and Safety” strategy. It also seems more likely that directors and boards of companies can be prosecuted under so called ‘Corporate Killing’ legislation. In addition, the Health and Safety Executive appears more interested in taking action under provisions of the existing Health and Safety Law (S37) for offences which have been committed with the ‘consent, connivance or attributable to neglect’ of officers.

Litigation

ScottishPower is not aware of any material pending legal proceedings, other than ordinary routine litigation incidental to the business of the group, to which ScottishPower or any of its subsidiaries is a party, or any such proceedings known to be contemplated by any governmental authority.

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SUMMARY OF KEY OPERATING STATISTICS

Table 1—Summary of PacifiCorp generating facilities

	Location	Energy source	Installation dates	Nameplate rating (MW)		Plant net  capability (MW)
Hydro-electric plants
Swift	Cougar, WA	Lewis River	1958	240.0		263.6
Merwin	Ariel, WA	Lewis River	1932-1958	135.0		144.0
Yale	Amboy, WA	Lewis River	1953	134.0		134.0
Five North Umpqua Plants	Toketee Falls, OR	N. Umpqua River	1949-1956	133.5		137.5
John C. Boyle	Keno, OR	Klamath River	1958	80.0		84.0
Copco Nos. 1 and 2 Plants	Hornbrook, CA	Klamath River	1918-1925	47.0		54.5
Clearwater Nos. 1 and 2 Plants	Toketee Falls, OR	Clearwater River	1953	41.0		41.0
Grace	Grace, ID	Bear River	1914-1923	33.0		33.0
Prospect No. 2	Prospect, OR	Rogue River	1928	32.0		36.0
Cutler	Collingston, UT	Bear River	1927	30.0		29.1
Oneida	Preston, ID	Bear River	1915-1920	30.0		28.0
Iron Gate	Hornbrook, CA	Klamath River	1962	18.0		20.0
Soda	Soda Springs, ID	Bear River	1924	14.0		14.0
Fish Creek	Toketee Falls, OR	Fish Creek	1952	11.0		12.0
33 minor hydro-electric plants	Various	Various	1896-1990	89.3	*	89.1	*
Subtotal (53 hydro-electric plants)				1,067.8		1,119.3
Thermal electric plants
Jim Bridger	Rock Springs, WY	Coal-Fired	1974-1979	1,541.1	*	1,413.4	*
Huntington	Huntington, UT	Coal-Fired	1974-1977	996.0		895.0
Dave Johnston	Glenrock, WY	Coal-Fired	1959-1972	816.8		762.0
Naughton	Kemmerer, WY	Coal-Fired	1963-1971	707.2		700.0
Hunter 1 and 2	Castle Dale, UT	Coal-Fired	1978-1980	727.9	*	662.5	*
Hunter 3	Castle Dale, UT	Coal-Fired	1983	495.6		460.0
Cholla Unit 4	Joseph City, AZ	Coal-Fired	1981	414.0	*	380.0	*
Wyodak	Gillette, WY	Coal-Fired	1978	289.7	*	268.0	*
Carbon	Castle Gate, UT	Coal-Fired	1954-1957	188.6		175.0
Craig 1 and 2	Craig, CO	Coal-Fired	1979-1980	172.1	*	165.0	*
Colstrip 3 and 4	Colstrip, MT	Coal-Fired	1984-1986	155.6	*	144.0	*
Hayden 1 and 2	Hayden, CO	Coal-Fired	1965-1976	81.3	*	78.0	*
Blundell	Milford, UT	Geothermal	1984	26.1		23.0
Gadsby	Salt Lake City, UT	Gas-Fired	1951-1955	251.6		235.0
Little Mountain	Ogden, UT	Gas-Fired	1971	16.0		14.0
Hermiston	Hermiston, OR	Gas-Fired	1996	237.0	*	236.0	*
James River	Camas, WA	Black Liquor	1996	52.2		52.0
Subtotal (17 thermal electric plants)				7,168.8		6,662.9
Other plants
Foote Creek	Arlington, WY	Wind Turbines	1998	32.6	*	32.6	*
Subtotal (1 other plant)				32.6		32.6
Total hydro, thermal and other generating facilities(71)				8,269.2		7,814.8

Notes:

* Jointly owned plants; amount shown represents PacifiCorp’s share only.

Hydro-electric project locations are stated by locality and river watershed.

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Table 2—PacifiCorp recoverable coal reserves as at 31 March 2002

Location	Plant served	Recoverable tons	Notes
		(in millions)
Craig, Colorado	Craig	50	(1	)
Emery County, Utah	Huntington and Hunter	68	(2	)
Rock Springs, Wyoming	Jim Bridger	100	(3	)

Notes:

1 These coal reserves are leased and mined by Trapper Mining, Inc., a Delaware non-stock corporation operated on a cooperative basis, in which PacifiCorp has an ownership interest of 21.4%.

2 These coal reserves are mined by PacifiCorp subsidiaries.

3 These coal reserves are leased and mined by Bridger Coal Company, a joint venture between Pacific Minerals, Inc., a subsidiary of PacifiCorp, and a subsidiary of Idaho Power Company. Pacific Minerals, Inc. has a two-thirds interest in the joint venture.

Coal reserve estimates are subject to adjustment as a result of the development of additional data, new mining technology and changes in regulation and economic factors affecting the use of such reserves.

Table 3—PacifiCorp Electricity GWh energy sales by customer class

Electricity sales, by class of customer, for the years ended 31 March 2002, 2001 and 2000 were as follows:

	2002	%	2001	%	2000	%
Gigawatt hours sold
—Residential	13,395	19	13,455	18	13,028	16
—Commercial	13,810	19	13,634	18	12,827	16
—Industrial	19,611	27	20,659	27	20,488	25
—Government, Municipal and Other	711	1	705	1	663	1
—Total Retail Sales	47,527	66	48,453	64	47,006	58
—Wholesale Sales and Market Trading	24,438	34	27,502	36	34,327	42
Total GWh Sold	71,965	100	75,955	100	81,333	100

Table 4—PacifiCorp transmission and distribution systems key information 2001/02

	Pacific Power		Utah Power		Total
Franchise area	76,173	sq miles	58,977	sq miles	135,150	sq miles
System maximum demand	3,808	MW	4,091	MW	7,899	MW
Transmission network (miles)
—Underground	—		—		—
—Overhead	6,827		8,087		14,914
Distribution network (miles)
—Underground	4,863		7,653		12,516
—Overhead	25,876		17,896		43,772

Table 5—Total electricity units distributed in Pacific Power service area (GWh)

Year	Residential	%	Commercial	%	Industrial	%	Other	%	Total
1997/98	7,885	31	6,770	26	10,689	42	139	1	25,483
1998/99	7,994	32	6,908	27	10,166	40	128	1	25,196
1999/00	7,612	31	6,766	27	10,167	42	122	—	24,667
2000/01	7,768	31	7,041	28	10,164	40	130	1	25,103
2001/02	7,537	31	6,932	29	9,743	40	129	—	24,341

Table 6—Total electricity units distributed in Utah Power service area (GWh)

Year	Residential	%	Commercial	%	Industrial	%	Other	%	Total
1997/98	4,940	24	5,306	25	10,082	48	556	3	20,884
1998/99	4,998	24	5,392	26	10,056	48	517	2	20,963
1999/00	5,416	24	6,061	27	10,321	46	541	3	22,339
2000/01	5,687	24	6,593	28	10,495	45	575	3	23,350
2001/02	5,858	25	6,878	30	9,868	43	582	2	23,186

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Table 7—Sources of ScottishPower owned generating capacity and output in the UK and the Republic of Ireland as at 31 March 2002

	Notes	Number of generating sets and/or installed capacity MW	Net output capacity MW	Maximum capacity available MW
Coal
Longannet		4 x 600	2,304
Cockenzie		4 x 300	1,152
	1		3,456	2,880
Gas Turbine
Rye House		1 x 715	715	715
Brighton	2	1 x 414	400	200
Knapton		1 x 42	42	42
Pumped Storage
Cruachan		4 x 100	400	400
Conventional Hydro
Galloway Scheme		109	106	106
Lanark Scheme		17	17	17
Windfarms
Beinn an Tuirc		46 x 0.66	30	30
Barnesmore		25 x 0.6	15	15
Hagshaw Hill		26 x 0.6	16	16
P & L Windfarm	3	103 x 0.3	31	15
Rigged Hill		10 x 0.5	5	5
Corkey		10 x 0.5	5	5
Elliots Hill		10 x 0.5	5	5
Coal Clough	4	24 x 0.4	10	4
Carland Cross	4	15 x 0.4	6	3
Dun Law		26 x 0.66	17	17
Hare Hill		20 x 0.66	13	13
CHP		43	43	43
Total			5,332	4,531

Notes:

1 Scottish & Southern Energy is entitled to a supply of electricity from part of the capacity of ScottishPower’s coal-fired generating stations at Longannet and Cockenzie.

2 Brighton power station is owned by South Coast Power Limited, with Scottish Power Generation Limited and American Electric Power (the US parent company of SEEBOARD) each having a 50% ownership interest.

3 The P & L Windfarm is owned by CeltPower Limited, with Scottish Power Generation Limited and Tomen Power (Europe) BV each having a 50% ownership interest.

4 The windfarms at Coal Clough and Carland Cross are owned by a joint venture between Scottish Power Generation Limited, Western Power Distribution and Renewable Energy Systems, with Scottish Power Generation Limited having a 45% ownership interest.

Table 8—UK transmission and distribution systems key information 2001/02

	ScottishPower		Manweb		Total
Franchise area	22,950	km2	12,200	km2	35,150	km2
System maximum demand	4,200	MW	3,089	MW	7,289	MW
Transmission network (km)
—Underground	249		—		249
—Overhead	3,915		—		3,915
Distribution network (km)
—Underground	41,137		24,204		65,341
—Overhead	24,460		21,668		46,128

Table 9—Total electricity units distributed in the ScottishPower service area (GWh)

Year	Residential	%	Business	%	Total
1997/98	8,048	37	13,664	63	21,712
1998/99	8,345	37	14,023	63	22,368
1999/00	8,385	38	13,996	62	22,381
2000/01	8,505	38	14,189	62	22,694
2001/02	8,698	39	13,864	61	22,562

Table 10—Total electricity units distributed in the Manweb service area (GWh)

Year	Residential	%	Business	%	Total
1997/98	4,916	26	13,606	74	18,522
1998/99	5,037	29	12,287	71	17,324
1999/00	5,204	30	11,977	70	17,181
2000/01	5,460	32	11,826	68	17,286
2001/02	5,387	32	11,540	68	16,927

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FINANCIAL REVIEW

[PHOTO]

All figures below are before the impact of goodwill amortisation and exceptional items unless otherwise stated.

Overview of the year to March 2002

Group turnover for the year to 31 March 2002 decreased by £35 million to £6,314 million. Continuing operations’ turnover increased by £113 million to £5,523 million, with the US Division contributing revenues of £3,154 million, a rise of £31 million on the prior year due to an increase in unregulated revenues in PacifiCorp Power Marketing, Inc. (“PPM”), rate increases in PacifiCorp and foreign exchange benefits, offset by significant reductions in wholesale market prices. Turnover in the UK Division rose by £58 million to £2,121 million due to higher gas retail and wholesale revenues and increased output from new generating plant, partially offset by lower electricity retail sales due to lower volumes and prices. Power Systems’ turnover was £248 million, an increase of £24 million on last year due to higher regulatory sales volumes and prices. Turnover for discontinued operations fell by £148 million to £791 million due to our exit from UK Appliance Retailing, which resulted in lower group revenues year-on-year of £185 million, offset in part by year-on-year revenue growth by Southern Water of £7 million and by Thus of £30 million.

Cost of sales of £4,411 million were £3 million higher than 2000/01. Continuing operations’ cost of sales increased by £83 million to £3,920 million mainly due to gas purchase costs in the UK Division for Rye House power station, which was acquired in March 2001. US Division cost of sales were broadly in line with the prior year as lower purchase volumes and prices in the regulated business were offset by the growth in PPM and foreign exchange movements. Cost of sales for discontinued operations fell by £80 million mainly due to our exit from UK Appliance Retailing early in the year. Transmission and distribution costs were £9 million lower at £513 million, reflecting lower net operating costs in Power Systems. Administrative expenses increased by £27 million in the year. Within continuing operations, increased depreciation charges in both the UK and US and foreign exchange movements were partly offset by lower discontinued operations’ costs, due to our exit from UK Appliance Retailing. Depreciation for the year for continuing operations increased by £46 million to £409 million, reflecting recent investment in new generation in the US and the acquisition of Rye House in the UK. Depreciation for the year for discontinued operations increased from £118 million to £146 million.

Group operating profit for the year to 31 March 2002 reduced by £26 million to £944 million, with operating profit from continuing operations falling by £15 million to £801 million. The challenging conditions experienced in the UK energy market and the price premium currently being borne under the Nuclear Energy Agreement (“NEA”) resulted in a fall of £44 million in the UK Division’s profit. However, this was substantially offset by the benefits derived from the operating cost saving programme within Power Systems, where operating profit increased by £14 million in the year, and by the recovery in PacifiCorp’s operating profit in the US. The US Division reported year-on-year profit improvement of £16 million after incurring some $300 million of additional excess net power costs earlier this year as a result of the unprecedented fall in wholesale price levels in the western US market. Operating profit for our discontinued operations decreased by £11 million to £144 million, as a result of a £5 million fall in Southern Water’s profit to £216 million and an increase in Thus’ losses of £6 million to £64 million for the period to 19 March 2002, the date of the demerger.

Exceptional items of £1,326 million (before interest and tax) have been recognised in the year to 31 March 2002. These exceptional items relate to the disposal of Southern Water and UK reorganisation costs recognised in the fourth quarter and a charge of £120 million associated with our disposal of and withdrawal from UK Appliance Retailing which was recognised in the first quarter results. An exceptional charge of £121 million was incurred last year in respect of the costs of implementing the PacifiCorp Transition Plan.

The net interest charge for the year to 31 March 2002, excluding exceptional interest, increased by £46 million to £379 million as a result of the higher debt levels in the UK and US, partly offset by lower interest rates in the UK. The exceptional interest charge of £31 million principally relates to costs associated with restructuring the debt portfolio, as a consequence of the sale of Southern Water.

Profit before tax for the full year fell by £61 million to £567 million. Including the impact of goodwill amortisation and exceptional items the loss before tax was £939 million compared to a profit before tax of £380 million in the prior year. The tax charge for the year was £122 million before taking account of tax relief of £39 million relating to exceptional charges. The corresponding amounts for 2000/01 were £141 million and £46 million, respectively. The effective rate of tax on profits before goodwill amortisation and exceptional items was 21.5% (2000/01 22.5%).

Net debt increased in the year by £923 million to £6,208 million at 31 March 2002. Cash inflows from operating activities of £1,248 million funded capital expenditure of £1,245 million in the year. Interest, tax and dividend payments of £960 million and the £70 million redemption of preferred stock by PacifiCorp were partly offset by net receipts of £103 million from business disposals, and other inflows. Gearing (net debt/shareholders’ funds) increased to 131% from 90% at 31 March 2001. Due to the timing of the

30

completion of the Southern Water disposal, the year-end net debt position does not reflect the £2.05 billion gross proceeds, including debt assumed by the purchaser, as a result of the sale. The cash consideration, which was received during April 2002, has been used to reduce group net debt and results in pro forma gearing at 31 March 2002 of 89%.

Group earnings per share were 26.12 pence compared with 27.86 pence last year, due to lower UK divisional profit and higher interest charges. Earnings per share including the impact of goodwill amortisation and exceptional items resulted in a loss per share of 53.71 pence compared to earnings per share of 16.80 pence last year. Earnings per share increased by 45% to 22.59 pence for the second half compared to the corresponding period last year.

Dividends for the year included a ‘dividend in specie’ of £437 million arising on the demerger of Thus. The full year cash dividend was up 5% on last year at 27.34 pence per share, consistent with our stated aim of 5% annual increase in dividends to March 2003.

Key group financial information is shown in Table 11.

Table 11—Key Group Financial Information

	2001/02	2000/01
Operating profit (£m)*	944.1	970.2
Profit before tax (£m)*	567.1	628.0
Earning per share (pence)*	26.12	27.86
Dividends per share (pence)**	27.34	26.04

* Before goodwill amortisation and exceptional items.

** Cash dividends, excluding ‘dividend in specie’ on demerger of Thus.

Business Reviews

US Division

Turnover in the US Division was £3,154 million, an increase of £31 million on last year. Excluding the effect of foreign exchange, residential and commercial revenues increased by £35 million or 6% and £26 million or 5% respectively, mainly as a result of price increases and customer growth partly offset by lower volumes due to weather and the impact of demand side management programmes. Industrial revenues were down by £18 million as a result of a 5% decrease in volumes due to lower irrigation usage and the impact of US economic conditions. A 22% decrease in average short-term firm and spot market wholesale prices ($107/MWh to $83/MWh) and lower long-term volumes have significantly impacted wholesale revenues in the year. Partially offsetting this was an increase in short-term firm and spot volumes, leaving turnover from wholesale activities down by £275 million or 19% on last year. Other revenue growth mainly came from our non-regulated PPM business where revenues were up by £156 million to £173 million and from favourable foreign exchange movements of £91 million.

For the year, the US Division’s operating profit increased by £16 million to £367 million despite the impact of additional excess power costs of $300 million incurred in the first six months. Increases in regulatory rates charged to customers and other revenues of £72 million and continued Transition Plan savings of £24 million, were offset by higher depreciation on regulated assets of £25 million, costs of strategic and risk initiatives of £45 million and other movements of £10 million including higher net power costs and foreign exchange movements. Operating profits for the second half of the year have seen a strong recovery and were £326 million higher than for the first six months. This was as a result of lower power purchase costs, regulatory rate increases and continued progress with the Transition Plan, offset in part by planned additional costs on strategic projects, risk mitigation and depreciation arising from new investment activities.

The key financial information is shown in Table 12.

Table 12—US Division

	2001/02	2000/01
External turnover (£m)	3,153.8	3,122.3
Operating profit (£m)*	366.9	351.3

* Before goodwill amortisation and exceptional item.

UK Division

Turnover for the UK Division grew by £58 million to £2,121 million for the year. Turnover was £106 million higher due to sales from Rye House power station. As a result of the decrease in wholesale market prices, agency turnover fell by £7 million despite volume growth from 3,874 GWh to 4,656 GWh and export sales in England and Wales reduced by £16 million, with volumes 22 GWh lower at 4,539 GWh. Sales from exports via the Northern Ireland Interconnector of 356 GWh improved turnover by £8 million in the year. Turnover also increased due to higher wholesale gas sales. Supply turnover was down on last year by £60 million with higher retail gas sales of £48 million and increased turnover from out-of-area customer gains of £54 million, offset by loss of market share and lower prices in our home areas which reduced turnover by £162 million. Overall customer numbers have been maintained at 3.5 million, and domestic retention rates are broadly in line with the industry average of 67% (source, Ofgem January 2002).

Operating profit in the UK Division fell by £44 million to £79 million, primarily due to the impact of falling wholesale market prices and the burden of the NEA. As a result of these market pressures, generation margins were £63 million lower than last year. Partially offsetting this was an improvement in electricity and gas retail margins of £29 million after the increased cost of acquiring new customers. The results for the year also include the New Electricity Trading Arrangements (“NETA”) system error of £10 million reported in the first quarter.

The key financial information is shown in Table 13.

Table 13—UK Division

	2001/02	2000/01
External turnover (£m)	2,121.4	2,063.8
Operating profit (£m)*	78.7	122.7

* Before goodwill amortisation and exceptional item.

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Infrastructure Division

Power Systems

Power Systems’ turnover increased from £224 million last year to £248 million, an increase of £24 million. Power Systems’ sales are still mainly internal to our supply business but, as customer retention in our home markets has declined due to competition, Power Systems external sales have increased as distribution and transmission use of system charges are recovered from third party suppliers.

Power Systems’ operating profit improved by £14 million to £355 million, as it continued to deliver financial upsides from its restructuring programme, with operating cost reductions of £39 million achieved during the year. These savings have offset the impact of regulatory price reductions experienced in the first half of the year and a gain on business disposals reported within last year’s results of £18 million. Power Systems remains on target to deliver £75 million of cash cost savings by March 2003 and identified a further £33 million of operating cost reductions by March 2004.

Southern Water

Turnover from Southern Water increased by £7 million to £430 million. This was primarily due to allowed regulatory price increases and customer growth from 11,000 new connections, partly offset by the move to measured supply and also from surface water rebates.

Southern Water’s operating profit of £216 million fell by £5 million as a result of new capital obligation costs and increased depreciation charges, offset in part by £11 million of cost savings. Southern Water’s results are now reported as part of discontinued operations.

The key financial information is shown in Table 14.

Table 14—Infrastructure Division

	2001/02	2000/01
External turnover (£m)
—Power Systems—continuing operations	247.6	223.7
—Southern Water—discontinued operations	429.9	422.4
Total	677.5	646.1
Operating profit (£m)
—Power Systems—continuing operations	354.9	341.3
—Southern Water—discontinued operations	216.3	221.6
Total	571.2	562.9

Other Discontinued Activities

UK Appliance Retailing

The decision to withdraw from the loss-making UK Appliance Retailing business was announced in June 2001. The disposal of part of the business to Powerhouse Retail finalised in October 2001 and the closure of the remaining operations is now complete. An exceptional charge of £120 million was recognised in the first quarter following this decision. UK Appliance Retailing’s turnover of £132 million and operating loss of £9 million for the year are disclosed within discontinued operations.

Thus

The demerger of Thus was successfully completed on 19 March 2002. The financial results of the group include the results of Thus up to this date, which are included within discontinued operations.

Turnover for Thus to 19 March 2002 was £30 million higher than last year at £229 million mainly due to increased data and telecoms revenues. Thus incurred an operating loss of £64 million, an increase of £6 million on last year. Despite overcapacity and falling demand depressing the wholesale telecoms sector in general, Thus continued to deliver strong growth in Earnings Before Interest, Tax, Depreciation and Amortisation (“EBITDA”) which improved from negative £21 million for the prior financial year to positive £2 million for the period up to demerger.

The key financial information is shown in Table 15.

Table 15—Thus and UK Appliance Retailing

	2001/02		2000/01
External turnover (£m)
—Thus	229.1		199.4
—UK Appliance Retailing	132.3		317.7
Operating loss (£m)*
—Thus	(63.7	)	(58.0	)
—UK Appliance Retailing	(9.0	)	(8.7	)

* Before goodwill amortisation.

Interest, Tax, Earnings and Dividends

Interest

The net interest charge for the year, excluding exceptional interest, was £379 million an increase of £46 million on 2000/01, primarily due to higher levels of debt in both the UK and US. The net proceeds from the sale of Southern Water were received in April 2002. The UK interest charge rose by £30 million to £214 million and represented an average interest rate for the year of 6.7% compared with 7.4% in 2000/01. The exceptional UK interest charge of £31 million principally relates to the restructuring of the group debt portfolio as a consequence of the sale of Southern Water. The interest charge for the US increased by £32 million to £172 million, with average interest rates falling to 6.5% compared to 6.6% in the prior year. Also included within interest is a £7 million benefit due to foreign exchange hedging. Interest cover for the year was 2.5 times compared with 3.0 times for 2000/01.

Tax

The taxation charge for the year was £122 million, £19 million lower than 2000/01. This amount excludes an exceptional tax credit of £39 million on the exceptional charges arising during the year as a result of the disposal of and withdrawal from our UK Appliance Retailing business and restructuring of the debt portfolio following the decision to sell Southern Water. The group’s effective tax rate before goodwill amortisation and exceptional items was 21.5% compared to 22.5% in the

32

previous year. The rate benefited by the release of provisions made in prior years following agreement with the tax authorities on the treatment of specific items. Although corporate tax rates in the US are higher than those in the UK, the financial structure of the group results in a reduction in the amount of overseas tax payable. Including goodwill amortisation and exceptional items resulted in a tax charge of £83 million on a loss before tax of £939 million compared to a tax charge of £95 million on profits before tax of £380 million in the previous year.

Key interest and tax information is shown in Table 16.

Table 16—Interest and Tax

	2001/02		2000/01
Interest charge (£m)*	379.4		332.9
Tax charge (£m)*	122.0		141.1
Effective group tax rate**	21.5	%	22.5	%

* Before exceptional items.

** Before goodwill amortisation and exceptional items.

Earnings and Dividends

Excluding the impact of exceptional items and goodwill amortisation, profit after tax decreased by £42 million to £445 million primarily as a result of lower UK Division operating profit and increased interest charges. With a weighted average 1,838 million shares in issue during the year, earnings per share were 26.12 pence compared to 27.86 pence in the previous year. The loss after tax for the year, including the effect of goodwill amortisation and exceptional items, amounted to £1,022 million compared to a profit of £285 million for the prior year. The fall in profit is mainly due to higher exceptional charges in the current year associated with the sale of Southern Water of which £738 million was the write back of goodwill. In last year’s results, there was a pre-tax exceptional charge of £121 million for the cost of implementing the US Transition Plan.

The total cash dividends per share for the year of 27.34 pence were 5% higher than the 2000/01 dividends of 26.04 pence. This increase is consistent with our stated aim of growing dividends by 5% per annum, for each of the three financial years to March 2003. Dividends for the year also included a ‘dividend in specie’ of £437 million arising on the demerger of Thus on 19 March 2002. Group dividend cover, excluding exceptional items and goodwill amortisation, fell to 1.0 times from 1.1 times in the previous year.

Capital Expenditure, Cash Flow and Net Debt

Capital Expenditure

Net capital expenditure totalled £1,229 million in the year, an increase of £135 million on 2000/01, primarily as a result of significant investment in new generation assets within our US Division.

US Division

Capital expenditure within the US Division increased by £267 million to £576 million. Of this amount, £233 million was on new generation of which £31 million was spent on PacifiCorp’s regulated Gadsby Peakers plant. PPM spent £101 million on 47% of the Klamath Falls power station, a 484 MW natural gas-fired plant which was commissioned in July 2001, and £61 million on a 200 MW gas turbine plant at West Valley City, Utah. PPM also spent £20 million acquiring a 40% interest in a gas storage and hub services business in Alberta, Canada. Total capital spend for the non-regulated PPM business was £205 million. The regulated PacifiCorp business capital spend of £371 million consisted of new systems growth and maintenance of £285 million, £31 million on new generation mentioned above and £55 million on other capital projects including information technology.

UK Division

In the UK Division, capital expenditure reduced by £56 million to £104 million as a result of significant spend in the prior year on CHP generation plants and the Daldowie wastewater project. This year, the main areas of expenditure included £38 million on plant refurbishment, including the first phase of refurbishment of a hydro and pumped storage plant, and £15 million increasing the renewable generation capacity, including a 30 MW windfarm at Beinn an Tuirc. In Supply, capital expenditure of £24 million was primarily on improving business processes and new systems and represented a year-on-year reduction of £13 million.

Infrastructure Division

        Net capital expenditure for the Infrastructure Division amounted to £459 million, in line with the previous year. In the continuing Power Systems business, expenditure increased by £41 million to £192 million, which included spend of £168 million rebuilding, refurbishing and connecting new customers to the network to meet demand for new electricity supply and support new business opportunities. The remaining amount included spend on IT systems and on compliance with Ofgem requirements. Capital expenditure in the discontinued Southern Water business totalled £267 million, a fall of £41 million on 2000/01. This included £151 million spent on sewage treatment and disposal, and £62 million on water resources, treatment and distribution.

Thus

During the year, Thus incurred capital expenditure of £78 million to the date of demerger, a reduction of £81 million compared to the previous year. Expenditure was targeted on metropolitan network build and customer connections.

Cash Flow and Net Debt

Net cash flow from operating activities decreased from £1,412 million to £1,248 million, due to lower cash inflows in the US Division resulting from additional excess power costs in the first six months of the financial year. This was partly offset by lower tax payments and, after net interest payments and minority dividends, resulted in free cash flow for the group of £786 million compared to £888 million for the previous year. This funded payments on capital expenditure of £1,245 million, an increase of £101 million on the prior year mainly due to investment in new generation assets in the US. Cash inflows from disposals of £150 million primarily relate to the sale of the non-core synthetic fuels operations in the US and the collection of a note receivable relating to PacifiCorp’s mining and resource development business, NERCO, which was sold in 1993. Dividends paid to shareholders amounted to £497 million, up from £471 million last year, reflecting the 5% increase in dividends per share. Net debt at 31 March 2002 was £6,208 million, an increase of £923 million on the previous year and gearing (net debt/shareholders’ funds) increased to

33

131% from 90% at 31 March 2001. Due to the timing of the completion of the Southern Water disposal, the year-end net debt position does not reflect the £2.05 billion gross proceeds, including debt assumed by the purchaser, as a result of the sale. The cash consideration, which was received during April 2002, has been used to reduce group net debt and results in pro forma gearing at 31 March 2002 of 89%.

Key capital expenditure, cash flow and net debt information is shown in Table 17.

Table 17—Capital Expenditure, Cash Flow and Net Debt

	2001/02	2000/01
Net capital expenditure (£m)	1,229.4	1,094.8
Free cash flow (£m)	785.9	887.6
Net debt (£m)	6,208.4	5,285.1

Overview of the year to March 2001

For the year to 31 March 2001, group turnover grew significantly by £2,234 million (54%) to £6,349 million. The US Division contributed revenues of £3,122 million, an increase of £2,411 million on the four month period post acquisition in 1999/00. Increased prices and higher demand in the US resulted in revenues from retail customers growing by 6% year-on-year and, although US wholesale volumes fell by 20%, sales revenues more than doubled as a result of the significant increase in power prices. Turnover in the UK Division fell by £124 million to £2,064 million, as the impact of competition in the electricity supply market resulted in lower volumes and prices within the ScottishPower and Manweb areas. This was offset in part by electricity sales growth outside our home areas, significant year-on-year increases in gas sales and net volume gains within the generation wholesale market. Infrastructure Division turnover decreased by £37 million to £646 million as the impact of the regulatory price review on Southern Water, which is reported in the Accounts as a discontinued operation, contributed to a £51 million fall in revenues. This was offset in part by external growth in Power Systems as the impact of competition in our home markets led to a shift from internal to external sales.

Cost of sales increased by 82% to £4,407 million, reflecting the inclusion of a full year’s trading from the US Division compared to four months during 1999/00. Costs also increased as a result of higher US power purchase costs following the Hunter outage, a decrease in hydro availability and growth in the retail load. Transmission and distribution costs were higher by £171 million year-on-year, including the impact of a full year’s US costs of £158 million. Administrative expenses increased by £83 million in the year, including US costs of £48 million, and an increase in UK costs by £35 million, mainly as a result of the growth of Thus.

Despite the impact of the Hunter outage in the US and the regulatory reviews in the UK, operating profit for the year increased by £9 million to £970 million. The US Division contributed profits of £351 million compared to £152 million for the four month post acquisition period to 31 March 2000. In the UK Division the impact of competition on wholesale prices and the application of Ofgem’s revised cost allocations on supply margins resulted in decreased operating profit of £123 million compared to £156 million in the previous financial year. Operating profit the Infrastructure Division fell by £93 million as a result of the impact of the regulatory price reviews and costs arising from new capital projects commissioned at the discontinued Southern Water business, offset in part by a programme of cost saving initiatives introduced in both Power Systems and Southern Water.

Key group financial information is shown in Table 18.

Table 18—Key Group Financial Information

	2000/01	1999/00
Operating profit (£m)*	970.2	961.4
Profit before tax (£m)*	628.0	735.6
Earnings per share (pence)*	27.86	37.97
Dividends per share (pence)	26.04	24.80

* Before goodwill amortisation and exceptional items.

Business Reviews

US Division

        Turnover for the US Division was £3,122 million, an increase of £2,411 million on the four month period post acquisition in 1999/00. When comparing revenue on a like for-like basis, for a full twelve month period 1999/00, turnover increased by £845 million in 2000/01 due to the impact of high power prices on wholesale revenues and increased retail volumes. In the wholesale market, revenues increased by £718 million (102%) a result of substantial increases in short-term firm and spot market sales prices, offset in by lower wholesale volumes. The decrease in volumes was attributable to the sale of the Centralia plant and mine, lower hydro availability, the outage of the Hunter unit and the increase in retail load requirements. All of these factors impacted the amount of power available to sell on the short-term and spot market. Revenue grew by £90 million within the retail markets reflecting customer number and volume growth within the residential and commercial sectors, and increased prices throughout the residential and industrial sectors. Other revenues increased by £37 million primarily as a result of growth in wheeling sales from increased usage of PacifiCorp’s transmission system by third parties.

Table 19—US Division

	2000/01	1999/00
External turnover (£m)	3,122.3	711.7
Operating profit (£m)*	351.3	151.7

* Before goodwill amortisation and exceptional item.

Figures for 1999/00 represent the external turnover and operating profit for the four months from date of acquisition to 31 March 2000.

34

The US Division reported operating profit of £351 million, which included the impact of the Hunter outage. Strong economic growth and abnormal temperatures led to an increase in retail demand throughout the western US. This, coupled with lower than normal hydro generation, resulted in demand exceeding supply and exposed the division to high power prices. Purchased power costs increased year-on-year by over £1 billion (159%), however these were largely offset by increased wholesale revenues.

The key financial information is shown in Table 19.

UK Division

Turnover for the UK Division was £2,064 million, a fall of £124 million on the previous year, as a result of lower revenues in the residential electricity markets, offset in part by higher generation sales. Total generation revenues increased by £71 million in the year to £356 million, with a higher proportion of sales being made to third parties due to the impact of competition. Gas and other revenues rose by £51 million, the acquisition of Rye House power station in March 2001 contributed additional revenues of £8 million and higher volumes resulted in agency sales growth of £53 million. This was partly offset by lower export sales in England & Wales, which fell by £41 million, with volumes 1,705 GWh lower at 4,561 GWh. Electricity supply sales within our home areas of Scotland and Manweb reduced year-on-year by £153 million and £84 million respectively, due to lower volumes and the effect of competition hitting customer retention levels and forcing prices downward. Outside the home areas, electricity sales increased by £25 million to £209 million, reflecting customer gains and volume growth in our domestic and small business markets. Strong growth was also experienced in gas and other energy sales which increased by £17 million to £239 million. The business now supplies 3.5 million electricity and gas customers in the UK.

The UK Division contributed operating profit of £123 million for the year, down £34 million compared with the prior year. Generation profits fell during the year by £12 million due to the continuing effects of wholesale prices reduced by competition. The new 400 MW combined-cycle gas turbine plant at Brighton became operational during the year and produced a contribution to joint venture operating profits of £8 million in the year. Supply profits decreased during the year by £22 million, primarily as a result of the application of Ofgem’s revised cost allocations in the year. Electricity margins in our home areas improved as the business continued to focus on value and benefits from lower generation and use of system costs. In addition, the contribution from new electricity customers outside our home areas and from gas customers increased by £12 million. These margin increases were partly offset by increased costs of capturing and serving our customer base and increased system depreciation charges.

The key financial information is shown in Table 20.

Table 20—UK Division

	2000/01	1999/00
External turnover (£m)	2,063.8	2,187.9
Operating profit (£m)*	122.7	156.3

* Before goodwill amortisation and exceptional items.

Infrastructure Division

Power Systems

Power Systems sales are up by £14 million to £224 million. In the past, sales have been mainly internal to our Supply business, but as a result of competition in home markets, Power Systems’ external sales continue to increase as distribution and transmission use of system charges were recovered from other electricity suppliers. Partly offsetting this is a fall in non regulated income, including a business disposal during the year.

Power Systems’ operating profit fell by £27 million to £341 million for the year. The reduction was attributable to the application of Ofgem’s revised cost allocations, which reduced prices allowed under the distribution and transmission regulatory review, the impact of which was partly offset by savings in controllable costs and an £18 million gain on the sale of the contracting business.

Southern Water

Southern Water’s contribution to group turnover decreased by £51 million to £422 million following the OFWAT review, with measured sales reducing by £14 million and unmeasured sales £34 million lower than the previous year. New customer connections during the year were just over 13,000 and 21,000 customers opted to switch to metered supply.

Southern Water contributed £222 million to operating profits, £66 million lower than the prior year, with reduced revenues following the OFWAT review and new costs arising from recently commissioned capital schemes offset in part by cost saving initiatives. Southern Water’s results are now reported as part of discontinued operations.

The key financial information is shown in Table 21.

Table 21—Infrastructure Division

	2000/01	1999/00
External turnover (£m)
—Power Systems—continuing operations	223.7	210.2
—Southern Water—discontinued operations	422.4	473.2
Total	646.1	683.4
Operating profit (£m)*
—Power Systems—continuing operations	341.3	368.4
—Southern Water—discontinued operations	221.6	287.4
Total	562.9	655.8

* Before exceptional items.

Other Discontinued Activities

UK Appliance Retailing

The UK Appliance Retailing business turnover was £318 million in the year, £12 million lower than in 1999/00. The operating loss was £9 million compared to the previous year’s profit

35

of £7 million, largely as a result of competitive trading conditions.

Thus

Total turnover from Thus was £234 million, up £17 million (8%) on the previous year, after allowing for the disposal of the mobile telephone business in the prior year. Second half sales grew by 25% to £130 million compared with the first half and by 12% year-on-year. Total business service sales grew 31% to £160 million year-on-year, with second half sales up 39% to £93 million over the first half and by 37% year-on-year. External turnover for the full year increased by 13% to £199 million on a like-for-like basis.

Thus continued with the ongoing investment in its national network and development of its services. Operating losses were £58 million for the twelve months to March 2001, compared to a loss of £10 million for the equivalent period in 1999/00.

The key financial information is shown in Table 22.

Table 22 —Thus and UK Appliance Retailing

	2000/01		1999/00
External turnover (£m)
—Thus*	199.4		177.1
—UK Appliance Retailing	317.7		329.2
Operating (loss)/profit (£m)**
—Thus	(58.0	)	(9.5	)
—UK Appliance Retailing	(8.7	)	7.1

* Adjusted for disposal of mobile telephone business in 1999/00.

** Before goodwill amortisation and exceptional item.

Interest, Tax, Earnings and Dividends

Interest

The net interest charge of £333 million was £105 million higher than in 1999/00 due to the inclusion of a full year’s trading from PacifiCorp and continued capital investment. The UK interest charge for the year was £184 million and represented an average rate for the year of 7.4%, versus 7.9% in 1999/00. The interest charge for PacifiCorp was £140 million, including benefits from the sale of Powercor and Centralia in the year, resulting in an average interest rate of 6.6%. In addition, interest charges were increased by £9 million as a result of foreign exchange. Interest cover was 3.0 times against 4.2 times in the prior year.

Tax

The taxation charge for the year was £141 million, £66 million lower than 1999/00. This amount excludes an exceptional tax credit of £46 million on the exceptional charge for the costs associated with the PacifiCorp Transition Plan. The group’s effective tax rate before goodwill amortisation and exceptional items was 22.5% compared to 28.1% in the previous year.

Earnings and Dividends

The profit after tax for the year including the effect of goodwill amortisation and exceptional items amounted to £285 million, a decrease of £602 million, primarily as a result of the exceptional gain from the partial flotation of Thus reflected in the Accounts to March 2000. Excluding the impact of exceptional items and goodwill amortisation, profit after tax decreased by £42 million to £487 million, reflecting the impact of the UK regulatory reviews. With a weighted average 1,830 million shares in issue during the year, earnings per share were 27.86 pence, compared to 37.97 pence in the previous year.

The final quarter dividend of 6.51 pence per share brought the total dividends per share for the year to 26.04 pence, an increase of 5%, consistent with our stated aim of growing dividends by 5% per annum for each of the three financial years to March 2003. Group dividend cover, excluding exceptional items and goodwill amortisation, fell to 1.1 times from 1.5 times the previous year.

Treasury

The treasury focus during the year was to minimise interest payments and reduce risk. The group continues to ensure that borrowings are financed from a variety of competitive sources and that committed facilities are available both to cover uncommitted borrowings and to meet the financing needs of the group in the future. Cash requirements are subject to seasonal variations.

Since the PacifiCorp acquisition, the group’s external borrowings have been sourced in two separate pools. In the UK, Scottish Power UK plc (“SPUK”) continues to be the finance vehicle for the bulk of the UK activities. In the US, predominantly all of the debt is issued by PacifiCorp the regulated utility, and is entirely denominated in US dollars.

In both cases, regulatory constraints apply to financing activities. Scottish Power plc (“SP plc”) is not permitted to borrow from its subsidiaries with the exception of certain intermediate holding companies in the US ownership chain and is currently financed by way of dividend and external debt. During the year two £50 million bilateral 364 day committed facilities were arranged for SP plc. Both were fully drawn at the year end.

PacifiCorp’s principal debt limitations are a 60.0% debt to defined capitalisation test and interest coverage covenant contained in its principal credit agreements.

In addition, under the Public Utility Holding Company Act of 1935 there are restrictions on the ability of group companies to lend to or borrow from one another.

In the UK, financing activities have been heavily influenced by plans relating to the disposal or refinancing of Southern Water. In the latter half of the year no new long-term financing was put in place and, as at the balance sheet date, the amount of short-term debt reflects preparation for the receipt of sale proceeds.

Under SPUK’s Euro-Medium Term Note Programme, established in November 1997, two issues were undertaken earlier in the financial year. These were a £100 million increase to the £200 million, 20-year, 5.90% issue originally undertaken in February 2001 and a £100 million, 5-year, 6.50% issue in May 2001 which may, in certain circumstances, be extended to 40 years. Cumulative issues outstanding under the programme now total $3,146 million against a programme limit, which has been increased, of $7,000 million. As part of the annual update of the programme SP plc was added as an issuer, although no issues have been made since. SPUK will continue to issue bonds and notes under the programme which allows the UK

36

part of the group access to a variety of funding sources and the ability to tap market demand as and when appropriate. Following the sale of Southern Water it is not expected that any new issues will be made for some time.

As part of the group’s strategy to diversify funding sources, an A$650 million 10 year credit wrapped floating rate bond was issued in the Australian market swapped into floating rate Sterling. Total borrowings from the European Investment Bank (“EIB”) amount to £328 million, although £129 million of this in respect of Southern Water was repaid following completion of the sale as agreed under the terms of the sale and purchase agreement with First Aqua Limited. During the year SPUK has taken on no more index-linked liabilities which total £275 million, both through issues of debt and through swapping fixed rate debt into index-linked. This represents around 8% of the UK debt portfolio in recognition of the fact that a large percentage of UK revenues are linked to inflation.

In June 2001, SPUK replaced its expiring £1,000 million revolving credit facility with a new five year facility of the same value. The facility was used principally as committed support for issues of commercial paper. This facility was cancelled following receipt of the proceeds of the sale of Southern Water in April.

On 1 October 2001, to comply with the Utilities Act, SPUK’s businesses were incorporated as subsidiaries. The new distribution, transmission and generation subsidiaries have provided upstream guarantees to support the majority of SPUK’s debt as existed at that date. New debt issued by SPUK after 1 October 2001 is not permitted to benefit from the guarantee of SPUK’s subsidiaries, SP Distribution Limited and SP Transmission Limited.

In November 2001, PacifiCorp issued bonds of $500 million and $300 million with maturities of 10 and 30 years, respectively. Like SPUK, PacifiCorp has also had to replace expiring bank facilities and therefore in June 2001, in conjunction with the SPUK transaction, two 364 day facilities were put in place totalling $880 million. These two bank facilities provided the opportunity to establish a group of core bank relationships that is common to both SPUK and PacifiCorp. Treasury transactions are focused on this group of banks. PacifiCorp is currently negotiating replacements to these existing bank facilities.

The group continues to manage its interest rate exposure by maintaining a large percentage of its debt at fixed rates of interest. This is done either directly by means of fixed rate debt issues or by use of interest and cross currency swaps to convert variable rate debt into fixed rate debt or fixed/variable nonfunctional foreign currency denominated debt into fixed rate functional currency debt. The use of derivative financial instruments relates directly to underlying anticipated indebtedness. The group treasury operates strictly within policies set out by the Board and is subject to regular examination by internal audit. The group amended its policy during the year, and now it is to maintain at least 50% (previously 70%) of its anticipated year-end debt at fixed interest rates.

In recognition of the long life of the group’s assets and anticipated indebtedness and to create financial efficiencies, the group entered into borrowing agreements for periods out to 2039. In addition, SPUK entered into derivative contracts to a notional value of £100 million which may result in fixed interest rates of 4.25% for periods out to 2030 on this notional amount. At 31 March 2002, the interest rate on some 66% (UK 55%, US 79%) of debt was fixed.

The weighted average period of maturity of year-end fixed debt and swaps was 11 years (UK 10 years, US 13 years).

During the financial year, the group implemented a policy to hedge part of the foreign currency value of PacifiCorp. This was done by creating notional US$ debt by the use of cross-currency interest rate swaps, cross-currency basis swaps and foreign currency forward contracts. The current amount of these hedges is $4,900 million representing approximately 80% of the net assets of PacifiCorp.

Both SPUK and PacifiCorp have credit ratings published by Moody’s Investor Services, Standard & Poor’s Ratings Group and The Fitch Group. SPUK’s long-term ratings for guaranteed debt, pre 1 October 2001, are now A2, A- and A from the three agencies respectively. SPUK’s long term ratings for unguaranteed debt are A3, A- and A from the three agencies respectively. PacifiCorp’s senior secured debt is rated A3, A, A and its unsecured debt is rated Baa1, BBB+ and A-. Short-term ratings of P-2, A-2 and F-1 apply to both companies. PacifiCorp Group Holdings, a subsidiary of PHI, has slightly lower ratings although they remain investment grade.

In November 2001, both PacifiCorp and SPUK had their credit ratings lowered by the rating agencies, citing the impact of high purchased power prices, the Hunter outage and the uncertainty and expected delay between incurring and recovering deferred net power costs from customers. Any adverse change to credit ratings of group companies could negatively impact on their ability to access capital markets and on the rates of interest that they would be charged for such access. The EIB debt within SP Transmission Limited and SP Distribution Limited contains credit downgrade language, which does not constitute default, and means that, should the ratings of SP Transmission Limited or SP Distribution Limited fall, the EIB will be entitled to ask for additional security in the form of a guarantee acceptable to the EIB. The EIB debt within SP Manweb plc contains financial covenants relating to interest cover and gearing of SP Manweb plc. Following the cancellation of SPUK’s £1,000 million revolving credit facility there are no other financial covenants within the UK group’s debt.

The proceeds of the sale of Southern Water have been partially used to repay SPUK’s short-term borrowings and to redeem the EIB debt of Southern Water as agreed under the sale and purchase agreement with First Aqua Limited.

The cash received will also be used on an ongoing basis to fund the existing business and to repay debt as it matures. The investment of surplus cash will be undertaken to maximise the return within Board approved policies which govern the ratings criteria, maximum investment and the maturity with any one counterparty. Counterparties are required to have a short-term rating of at least A-1, P-1 or F-1 from the three major rating agencies.

Contractual Obligations and Commercial Commitments

ScottishPower enters into various financial obligations and commitments in the normal course of business. Contractual financial obligations are considered to comprise known future cash payments that the group is required to make under contractual arrangements in place at 31 March 2002. Commercial commitments are defined as those obligations of the group which only become payable if certain pre-defined events occur.

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Table 23—Contractual Obligations at 31 March 2002 (£m)

Tables 23 and 24 detail the group’s contractual obligations and commercial commitments as of 31 March 2002.

	Within 1 year	Between 1 and 3 years	Between 3 and 5 years	After 5 years	Total
Loans and other borrowings (including overdrafts)	1,226.8	437.3	599.5	4,306.2	6,569.8
Finance leases	—	0.2	0.4	18.8	19.4
Operating leases	16.2	17.2	8.0	13.2	54.6
Firm purchase commitments	1,341.5	2,161.7	1,283.3	3,436.9	8,223.4
Capital commitments	190.4	48.5	—	—	238.9
Total contractual obligations	2,774.9	2,664.9	1,891.2	7,775.1	15,106.1

The ‘Loans and other borrowings’ figures in the above table are stated at book value at 31 March 2002.

Table 24—Commercial Commitments at 31 March 2002 (£m)

	Within 1 year	Between 1 and 3 years	Between 3 and 5 years	After 5 years	Total
Lines of credit	618.0	—	1,000.0	—	1,618.0
Standby letters of credit	38.5	119.8	50.2	—	208.5
Standby bond purchase agreements	67.8	87.4	—	—	155.2
Other commercial commitments	1.6	—	—	—	1.6
Total commercial commitments	725.9	207.2	1,050.2	—	1,983.3

The actual net capital expenditure incurred by the group for the year ended 31 March 2002 was £1,229 million. The group’s estimated net capital expenditure, which is subject to continuing review and revision, for the year ended 31 March 2003 is within the range of £700-£750 million. This estimate is lower than the current year spend and reflects the impact of the disposal of Southern Water and the demerger of Thus.

Quantitative and Qualitative Disclosures about Market Risk

Market Rate Sensitive Instruments and Risk Management

The following discussion about the group’s risk management activities includes “forward looking” statements that involve risk and uncertainties. Actual results could differ materially from those projected in the forward looking statements.

The tables in Note 21 (pages 80 to 85) summarise the financial instruments, derivative instruments and derivative commodity instruments held by the group at 31 March 2002, which are sensitive to changes in interest rates, foreign exchange rates and commodity prices. The group uses interest rate swaps, forward foreign exchange contracts and other derivative instruments to manage the primary market exposures associated with the underlying assets, liabilities and committed transactions. The group uses these instruments to reduce risk by essentially creating offsetting market exposures.

In the vast majority of instances, physically settled financial instruments held by the group match offsetting physical transactions and are not held for financial trading purposes. Subject to risk management controls, businesses may enter into financial transactions that are designed to improve the return on assets and that are structured around the physical assets of the group. Trading UK is authorised by the Financial Services Authority to undertake investment activity in the energy markets.

Financial Instruments and Risk Management

Overview

        The main financial risks faced by the group are interest rate risk, inflation risk, foreign exchange risk, liquidity risk, energy price risk and insurance risk. The Board has reviewed and agreed policies for managing each of these risks as summarised below. In order to mitigate the risks identified, the Board has endorsed the use of derivative financial instruments. The derivative financial instruments endorsed for use by the Board include swaps, both interest rate and cross currency, swaptions, caps, forward rate agreements, financial and commodity forward contracts, commodity futures and commodity options and weather derivatives.

Risk Management

Energy risk is governed globally by the Group Risk Management Committee (“GRMC”), chaired by the Finance Director. The group risk management policies and procedures as well as the UK and the US policies and procedures are designed to create consistent risk measurement, monitoring and management standards throughout the group. The day-today monitoring of the level of cover in place is handled by a corporate risk management function, reporting to the Finance Director independently of the business. Market exposures are quantified and controlled using a number of different risk measures. These include Value-at-risk (“VAR”) methods. VAR is a statistically-based measure of the potential loss on an exposure over a defined period to a given level of confidence. Additional risk measures are applied to quantify risks beyond the confidence intervals defined in the VAR methodology and volumetric risks in physical positions and their impact on business profits in addition to traded position value.

Trading UK is authorised to carry out activities to manage electricity and gas price risk. Electricity or gas price risk is defined as the possibility that a change in the cost of electricity or gas will either reduce the proceeds of electricity or gas sales or increase the costs of electricity or gas purchases. In the US, wholesale energy sales trading operates within defined policies for managing PacifiCorp’s electricity price and supply risks in meeting load requirements. Trading UK, and the wholesale energy sales trading function in the US, report monthly to a risk committee, and also report monthly to the GRMC.

The role of the group’s credit function is to set consistent standards for assessing and scoring the credit risk induced by contractual obligations of wholesale trading partners and industrial and commercial clients. A group credit committee provides an umbrella oversight for all credit decisions that overlap both the US and the UK markets. This ensures that each individual business is subject to strict concentration rules. The UK and the US credit committees provide local expertise to understanding the credit environment in each geographic location. All decisions are supported by a rigorous reporting of credit exposures and

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sophisticated credit scoring models. Credit approvals are subject to periodical and/or event driven reviews. Despite mitigation efforts, defaults by counterparties occur from time to time. To date, no such default has had a material adverse effect on ScottishPower.

The group treasury is authorised to conduct the day-to-day treasury activities of the group within policies set out by the Board. The treasury function reports regularly to the Board, through the monthly group financial review and is subject to both internal and external audit.

Interest Rate Risk Management

The group continues to access funding opportunities in the major global markets in a range of currencies at both fixed and floating rates of interest, using derivatives where appropriate, to convert the obligations and payments into fixed or floating rate functional currency.

The exposure to fluctuating interest rates is managed by either issuing fixed or floating rate debt or using a spectrum of financial instruments to create the desired fixed/floating mix. Flexibility in the fixed/floating mix is maintained by using interest rate caps that protect the group should rates rise, i.e. above the strike price, while maintaining the potential benefit should interest rates fall. The group amended its policy during the year, and now it is to maintain at least 50% (previously 70%) of its anticipated year-end debt at fixed interest rates. At 31 March 2002, 66% (2001 71%) of the group’s debt was either issued as fixed or converted to fixed rates using interest rate swaps.

All treasury transactions are undertaken to manage the risks arising from underlying activities and no speculative trading is undertaken. The counterparties to these instruments generally consist of financial institutions and other bodies with good credit ratings, i.e. “AA” rated by at least one of the following, Standard & Poor’s, Moody’s or Fitch. Although the group is potentially exposed to credit risk in the event of non-performance by counterparties, such credit risk is controlled through credit rating reviews of the counterparties and by limiting the total amount of exposure to any one party to levels agreed by the Board. The group does not believe that it is over exposed to any material concentration of credit risk.

Foreign Exchange Risk Management

Following the PacifiCorp acquisition the significance of foreign exchange has risen.

    Translation Risk

During 2001/02 it was decided to hedge $4,900 million, representing approximately 80%, of PacifiCorp’s net assets, as a long-term strategic hedge of the investment. As a result liabilities were created by means of cross currency interest rate and basis swaps and by means of forward foreign exchange contracts. The resulting interest flow in US dollars acts as a natural partial hedge to the translation of PacifiCorp’s profits but these profits are further hedged, up to three years into the future, by means of forward sales of US dollars. All foreign currency derivative contracts are subject to the same controls as interest rate derivatives referred to above.

    Transaction Risk

Transactions denominated in a foreign currency are not numerous in a group that consists, broadly, of two domestic businesses. Where they arise as a result of imports of capital or other goods denominated in foreign currencies the exposure is hedged as soon as it is known.

    Liquidity Risk Management

The group’s policy is to arrange that debt maturities are spread over a wide range of dates, thereby ensuring that the group is not subject to excessive refinancing risk in any one year. The group had undrawn committed revolving credit facilities totalling £1,618 million, as at 31 March 2002, which provide backstop liquidity should the need arise. SPUK’s £1,000 million revolving credit facility, which is included in Table 24, was cancelled following receipt of the proceeds of the sale of Southern Water in April 2002.

Energy Price Risk Management

    UK Business

NETA was introduced in England & Wales on 27 March 2001, replacing the previous ‘Pool’ mechanism for the sale and purchase of wholesale power in England & Wales. NETA provides for a bilateral wholesale market, with suppliers, traders and generators trading firm physical forward contracts for bulk electricity supply. In addition, a number of power exchanges for the trading of power futures have been set up, and a ‘Balancing Mechanism’ created for short-term trading of power. In addition to trading to directly manage our market price exposure in the England & Wales market, ScottishPower also manages its price exposure arising from sales within the Scottish market by trading forward contracts.

        The balancing mechanism, operated from 3 ¹/2 hours ahead of real-time (gate closure) up to real-time by the National Grid Company, is used to manage the grid system on a second by second basis. Market participants can participate actively in this market through the submission of bids and offers to vary their generation output or customer demand. The mechanism also provides for calculation and settlement of imbalance charges arising from the differences between parties’ contract positions and their actual physical energy flows.

The group has procedures in place to minimise exposure to uncertain balancing mechanism prices, that is, the possibility that the group will face high charges for shortfalls in physical energy or receive low revenues for surplus physical energy. These procedures involve Trading UK in entering into bilateral contracts for the sale and purchase of energy across a range of time periods to minimise exposure to the balancing mechanism. In addition, our portfolio of flexible generating assets in England and Scotland can be used up to gate closure to further minimise this exposure and also to attract premium income from providing flexible power to the balancing mechanism.

The group has also entered into longer-term (in excess of one year) arrangements to protect against longer-term volatility of power prices. The time periods covered by these longer-term arrangements are reviewed on a continuous basis to provide the desired level of price stability.

The group also has procedures in place to minimise exposure to short-term gas price variations. In a similar manner to our power price exposure management strategy, gas price risk is managed through the use of longer-term (in excess of one year) contracts, contracts with flexible delivery profiles and through the use of flexibility within our portfolio of power generating and gas storage assets.

Cover against volatile spot prices is built up on a rolling basis through the year and, at 31 March 2002, a significant proportion of the group’s exposure to power and gas price variations for the following financial year have been covered.

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A sensitivity analysis has been prepared to estimate the exposure to market risk related to gas and electricity price exposure of the UK businesses’ portfolio of load, plant and physical and financial instruments for electricity. Based on the UK businesses’ gas and electricity price exposure at 31 March 2002, a near-term adverse price change of 10.0% would have a negative impact on pre-tax earnings of £5.8 million in 2002/03 based on the then-current (at 31 March 2002) gas and electricity position over the 12 month period ending 31 March 2003.

US Business

PacifiCorp’s market risk to commodity price change is primarily related to its fuel and electricity purchases and sales arising principally from its electricity supply obligation in the US. This risk to price change is subject to fluctuations in weather, economic growth and generation resource availability which impacts supply and demand. Price risk is managed principally through the operation of its generation and transmission system in the western US and through its wholesale energy purchase and sales activities. Physically settled contracts are used to hedge PacifiCorp’s excess or shortage of net electricity for future months. The changes in market value of such contracts have had a high correlation to the price changes of the hedged commodity.

While PacifiCorp plans for resources to meet its current and expected retail and wholesale load obligations, resource availability, price volatility and load volatility may materially impact the power costs to PacifiCorp and profits from excess power sales in the future. Prices paid by PacifiCorp to provide certain load balancing resources to supply its load may exceed the amounts it receives through retail rates and wholesale prices. Regulatory approval of deferred accounting treatment for these excess costs mitigates a portion of this price risk, assuming recovery mechanisms are implemented.

To further mitigate commodity price risk, PacifiCorp has requested power cost adjustment mechanisms whereby, if granted by the utility commissions, all or part of actual power costs, above or below the level in rates, will be shared with customers.

PacifiCorp took steps in the financial year to manage commodity price volatility and reduce exposure. These steps included adding to its generation portfolio and entering into transactions that help to shape PacifiCorp’s system resource portfolio, including physical hedging products and financial temperature-related instruments that reduce resource and price risk on hot summer days. In addition, hydro–electric hedges were put in place for the next five years to limit volume and price risks associated with Pacific Northwest hydroelectric generation availability.

A sensitivity analysis has been prepared to estimate the exposure to market risk related to gas and electricity price exposure of the US businesses’ portfolio of load, plant and physical and financial instruments for electricity. Based on the US businesses’ gas and electricity price exposure at 31 March 2002, a near-term adverse price change of 10.0% would have a negative impact on pre-tax earnings of £1.4 million in 2002/03 based on the then-current (at 31 March 2002) gas and electricity position over the 12 month period ending 31 March 2003.

Fair Value of Derivative Contracts

Table 25 details the changes in the fair value of the group’s energy related and treasury derivative contracts from 1 April 2001 to 31 March 2002 and quantifies the reasons for the changes. Short-term energy contracts are valued based upon quoted market prices. Long-term energy contracts are valued using the appropriate forward market price curve. The forward market price curve is derived using daily market quotes from independent energy brokers and reporting services. Where relevant, contracts are separated into their component physical and financial swap and option legs. For certain contracts extending past 2006, the forward prices are derived using a fundamentals model (cost-to-build approach) that is updated as warranted to reflect changes in the market, at least quarterly. Interest rate swaps are valued by calculating the present value of future cash flows estimated using forward market curves. Interest rate swaptions are valued using the market yield curve and implied volatilities at the period end. Cross currency swaps are valued by adding the present values of the two sides of each swap: present values are calculated by discounting the future cash flows, estimated using the appropriate forward market curve for that currency, at the appropriate market discount rates. Forward foreign exchange contracts are valued using market forward exchange rates at the period end.

Table 25—Fair Value of Energy Related and Treasury Derivative Contracts

	£m
Fair value of contracts outstanding at 1 April 2001	64.9
Contracts realised or otherwise settled during the year	47.5
Changes in fair values attributable to changes in valuation techniques     and assumptions	120.1
Other changes in fair value	(546.7	)
Fair value of contracts outstanding at 31 March 2002	(314.2	)

	Within 1 year £m		Between 1 and 3 years £m		Between 3 and 5 years £m		After 5 years £m		Total £m
Prices actively quoted	(51.4	)	(18.9	)	—		—		(70.3	)
Prices based on models and other valuation methods	(15.4	)	(35.4	)	(37.9	)	(155.2	)	(243.9	)
Total	(66.8	)	(54.3	)	(37.9	)	(155.2	)	(314.2	)

Insurance Risk Management

The insurance industry has undergone dramatic change in the last year which were exacerbated further by the tragic events of September 11 and were characterised by restrictions in available capacity, increased costs and a general narrowing of available coverage.

Despite these changes in the market, the group renegotiated all of its main insurance policies in March 2002. Although there has been an increase in cost and in some areas a narrowing of cover, in other areas it has been possible to enhance the insurance coverage available.

Creditor Payment Policy and Practice

In the UK, the group’s current policy and practice concerning the payment of its trade creditors is to follow the Better Payment Practice Code to which it is a signatory. Copies of the Code may be obtained from the Department of Trade and Industry or from the website www.payontime.co.uk.

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The group’s policy and practice is to settle terms of payment when agreeing the terms of the transaction, to include the terms in contracts and to pay in accordance with its contractual and legal obligations. The group’s creditor days at 31 March 2002 for its UK businesses and US business were 27 days and 40 days, respectively.

Going Concern

The directors confirm that the company remains a going concern on the basis of its future cash flow forecasts and has sufficient working capital for present requirements.

Dividend Policy

In March 2002, the group announced its dividend policy to apply with effect from the year ending March 2004. ScottishPower reaffirmed its stated aim of growing dividends by 5% per annum nominal for the period to March 2003. Thereafter, the Board intends to adopt a dividend policy that reflects both the reduced proportion of the group’s profit derived from the UK regulated infrastructure businesses and the need to balance future investment with an appropriate dividend return for shareholders. Accordingly, with effect from the year ending March 2004, the group intends to target dividend cover, based on earnings before goodwill amortisation and exceptional items, in the range of 1.5 – 2.0 times, and ideally towards the middle of that range. The group intends to grow dividends broadly in line with earnings thereafter.

Accounting Developments

The UK Accounting Standards Board (“ASB”) did not issue any new standards during the year ended 31 March 2002. However, Financial Reporting Standard (“FRS”) 17 ‘Retirement benefits’, issued in November 2000, requires certain disclosures relating to pensions and other post-retirement benefits which have been included in this year’s Accounts. The accounting measurement rules in FRS 17 are not required to be implemented in the group’s Accounts until the year ending 31 March 2004. Had the measurement rules of FRS 17 been applied during the financial year 2001/02, net assets and reserves at 31 March 2002 would have been increased by approximately £27 million. Pre-tax profits would have been in line with those reported under the existing standard, with an increase in operating costs largely offset by a reduction in finance costs.

The Urgent Issues Task Force committee of the ASB issued a number of accounting pronouncements during the year. These pronouncements had no material impact on the group’s results and financial position.

The group’s results are also presented in accordance with US Generally Accepted Accounting Principles (“US GAAP”). The group’s US GAAP results have been materially impacted by Statement of Financial Accounting Standard (“FAS”) 133 ‘Accounting for Derivative Instruments and Hedging Activities’. The effect of the implementation of this standard on the group’s US GAAP results for the financial year is set out in Note 34 to the Accounts. The group implemented FAS 141 ‘Business Combinations’ and FAS 144 ‘Accounting for the Impairment or Disposal of Long-Lived Assets’ during the year.

Implementation of these new standards did not have a material impact on the group’s US GAAP results and financial position. In addition, the group implemented FAS 142 ‘Goodwill and Other Intangible Assets’ on 1 April 2002. FAS 142 prohibits the amortisation of goodwill and requires that goodwill be tested annually for impairment (and in interim periods if certain events occur which indicate that the carrying value of goodwill may be impaired). Goodwill amortisation charged to the profit and loss account, under US GAAP, for the year ended 31 March 2002, was £172.5 million. The group is currently evaluating the overall impact of adopting this standard on its results and financial position. FAS 143 ‘Accounting for Asset Retirement Obligations’ will be effective for the group beginning 1 April 2003. The group is currently evaluating the impact of adopting FAS 143 on its results and financial position. FAS 145 ‘Recission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No.13 and Technical Corrections’ will also be effective for the group beginning 1 April 2003. This standard is not expected to have a material impact on the group’s results and financial position.

Critical Accounting Policies

The group Accounts are prepared in accordance with UK Generally Accepted Accounting Principles (“UK GAAP”). This requires the directors to adopt those accounting policies which are most appropriate for the purpose of the Accounts giving a true and fair view. The group’s material accounting policies are set out in full on pages 56 to 60. In preparing the Accounts in conformity with UK GAAP, the directors are required to make estimates and assumptions that impact on the reported amounts of revenues, expenses, assets and liabilities. Actual results may differ from these estimates. Certain of the group’s accounting policies have been identified as the most critical accounting policies by considering which policies involve particularly complex or subjective decisions or assessments and these are discussed below. The discussion below should be read in conjunction with the full statement of accounting policies.

        Income from the sale of energy and measured water includes an estimate of the number and value of units supplied to customers between the most recent measurement and the year end. This is estimated based on the energy and water delivered each month compared to the amounts billed to customers. Estimates of unbilled units and debt are reviewed regularly to ensure that income is recognised only where there is sufficient reliability of the estimates.

The group estimates its provision for doubtful debts relating to trade debtors by a combination of two methods. Firstly, specific amounts are evaluated where information is available that a customer may be unable to meet its financial obligations. In these circumstances, assessment is made based on available information to record a specific provision against the amount receivable from that customer to adjust the carrying value of the debtor to the amount expected to be collected. In addition, a provision for doubtful debts within the portfolio of other debtors is made using historical experience and ageing analysis to estimate the provision required to reduce the carrying value of trade debtors to their estimated recoverable amounts. This process involves the use of assumptions and estimates which may differ from actual experience. Management of debt recovery is a key priority for the group and the estimates of provisions for doubtful debts are reviewed regularly. In late 2001, Enron declared bankruptcy. The group’s debtors due from Enron were not material to the group and provision has been made for the amount receivable, net of the effect of applying master netting agreements.

Tangible fixed assets, other than land, are generally depreciated on the straight line method over their estimated operational lives. Operational lives are estimated based on a number of factors including the expected usage of the asset, expected physical

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deterioration and technological obsolescence. Goodwill on acquisitions prior to 31 March 1998 was written off to reserves. Goodwill on subsequent acquisitions is amortised on a straight-line basis over its estimated useful economic life. The estimated useful economic life of the goodwill on acquisition of PacifiCorp is 20 years. This is based on an assessment of the long-term nature of PacifiCorp’s electricity business and the potential impact of change to the regulatory regime for utility companies in the US. In certain circumstances, accounting standards require tangible fixed assets and goodwill to be reviewed for impairment. When a review for impairment is conducted, the recoverable amount is assessed by reference to the net present value of the expected future cash flows of the relevant income generating unit (“IGU”), or disposal value if higher. The discount rate applied is based on the group’s weighted average cost of capital with appropriate adjustments for the risks associated with the IGU. Estimates of cash flows are consistent with management’s plans and forecasts. Estimation of future cash flows involves a significant degree of judgement.

US regulatory assets are only recognised where they comprise rights or other benefits which have arisen as a result of past transactions or events which have created an obligation to transfer economic benefits to a third party. The interpretation of these principles requires assessment of regulatory events to determine when an asset should be recognised. The application of this policy has generally led to US regulatory assets only being recognised when reflected in customers’ bills.

Provision is made for liabilities relating to environmental obligations when the related environmental disturbance occurs, based on the net present value of estimated future costs. Estimates of environmental liabilities are principally based on reports prepared by external consultants. The ultimate cost of environmental disturbance is uncertain and there may be variances from these cost estimates, which could affect future results.

Provision is made for the decommissioning of major capital assets where the costs are incurred at the end of the lives of the assets. Similarly, closure and reclamation costs are a normal consequence of mining with the majority of the expenditure incurred at the end of the life of the mine. Although the ultimate cost to be incurred is uncertain, estimates have been made of the respective costs based on local conditions and requirements.

The group’s tax charge is based on the profits for the year and tax rates in force. Estimation of the tax charge requires an assessment to be made of the potential tax treatment of certain items which will only be resolved once finally agreed with the relevant tax authorities. In particular, the tax returns of the group’s US businesses are examined by the Internal Revenue Service and state agencies on a several year lag. Assessment of the likely outcome of the examinations is based upon historical experience and the current status of examination issues.

The group operates a number of defined benefit pension schemes for its employees. In addition, other post-retirement benefits are provided to employees within the group’s US businesses. The nature of pensions and other post-retirement benefits is inherently long-term and future experience may differ from actuarial assumptions which are used to compute the group’s costs for pensions and other post-retirement benefits. The principal actuarial assumptions relate to the expected return on assets, future salary increases, pension increases, interest rates for costing liabilities and health care cost trends.

In addition to preparing the group Accounts in accordance with UK GAAP, the directors are also required to prepare a reconciliation of the group’s profit or loss and shareholders’ funds between UK GAAP and US GAAP. The adjustments required to reconcile the group’s profit or loss and shareholders’ funds from UK GAAP to US GAAP are explained in Note 34 to the Accounts. Certain of the group’s US GAAP accounting policies have been identified as the most critical US GAAP accounting policies and these are discussed below. The discussion below should be read in conjunction with the full explanation of US GAAP accounting policies set out in Note 34.

The group prepares its US GAAP financial information in accordance with FAS 71 ‘Accounting for the Effects of Certain Types of Regulation’ in respect of its regulated US business, PacifiCorp.

In order to apply FAS 71, certain conditions must be satisfied, including the following: an independent regulator must set rates; the regulator must set the rates to cover the specific costs of delivering service; and the service territory must lack competitive pressures to reduce rates below the rates set by the regulator. FAS 71 requires the group to reflect the impact of regulatory decisions and requires that certain costs be deferred on the balance sheet, under US GAAP, until matching revenue can be recognised. FAS 71 provides that regulatory assets may be capitalised, under US GAAP, if it is probable that future revenues, in an amount at least equal to the capitalised costs, will result from the inclusion of that cost in allowable costs for rate-making purposes. In addition the rate actions should permit recovery of the specific previously incurred costs rather than to provide for expected levels of similar future costs. An entity applying FAS 71 does not need absolute assurance prior to capitalising a cost, only reasonable assurance. If the group should determine that, in future, PacifiCorp no longer meets the criteria for continued application of FAS 71, the group could be required to write off its regulatory assets and liabilities, under US GAAP, unless regulators specify some other means of recovery or refund. PacifiCorp intends to seek recovery of all of its prudent costs, including stranded costs, in the event of deregulation. However, due to the current lack of definitive legislation, it is not possible to predict whether PacifiCorp will be successful.

        Because of potential regulatory and/or legislative actions in the various states in which PacifiCorp operates, the group may have regulatory asset write offs and charges for impairment of regulatory assets, under US GAAP, in future periods. Such impairment reviews would involve estimates of future cash flows including estimated future prices, cash costs of operations, sales and load growth forecasts and the nature of any legislative or regulatory cost recovery mechanism.

The group uses derivative instruments in the normal course of business, to offset fluctuations in earnings, cash flows and equity associated with movements in exchange rates, interest rates and commodity prices.

On 1 April 2001, the group adopted FAS 133. Certain of the group’s derivatives are treated as normal purchases and normal sales and are therefore excluded from the requirements of

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FAS 133. Derivatives falling within the scope of FAS 133 are required to be recorded in the balance sheet, under US GAAP, at fair value. Changes in the fair values of derivatives that are not designated as hedges are adjusted through earnings, under US GAAP, with the exception of long-term energy contracts that were in existence on 1 April 2001 and are included in PacifiCorp’s rate-making base. For these long-term energy contracts PacifiCorp received regulatory accounting approvals to adjust the fair value through establishment of regulatory assets and liabilities until the contracts are settled. For derivatives designated as effective hedges, the changes in fair values are recognised, under US GAAP, in accumulated other comprehensive income until the hedged items are recognised in earnings. The group’s future results, under US GAAP, could be impacted by changes in market conditions to the extent that changes in contract values are not offset by regulatory or hedge accounting.

To date the Derivatives Implementation Group (“DIG”) in the US has issued more than 100 interpretations to provide guidance in applying FAS 133. As the DIG or the Financial Accounting Standards Board in the US continue to issue interpretations, the group may be required to change its accounting treatment for certain of its derivative instruments and this could impact on the group’s US GAAP financial information in the future.

UK GAAP to US GAAP Reconciliation

The consolidated Accounts of the group are prepared in accordance with UK GAAP which differ in significant respects from US GAAP. Reconciliations of profit and equity shareholders’ funds between UK GAAP and US GAAP are set out in Note 34 to the Accounts. Under US GAAP, the loss for the year ended 31 March 2002 was £825 million after charging an extraordinary item, net of tax, of £8 million and before charging a cumulative adjustment for the effect of implementing FAS 133, net of tax, of £62 million compared to a profit of £387 million the previous year. Loss per share under US GAAP, before the cumulative adjustment for FAS 133, was 44.91 pence per share compared to earnings of 21.13 pence per share in 2000/01. Under US GAAP, the loss per share for the year ended 31 March 2002, after the cumulative adjustment for FAS 133, was 48.26 pence. In accordance with US GAAP, loss/earnings per share are stated based on US GAAP loss/earnings, without adjustments for the impact of the UK GAAP exceptional items and goodwill amortisation, as such additional measures of underlying performance are not permitted under US GAAP. The inclusion of UK GAAP exceptional items in the determination of earnings per share in accordance with US GAAP decreased earnings by £1,039 million or 56.53 pence per share in 2001/02. The inclusion of goodwill amortisation decreased earnings by £173 million or 9.39 pence per share in 2001/02 and by £164 million or 8.93 pence per share in 2000/01. Equity shareholders’ funds under US GAAP amounted to £5,850 million at 31 March 2002 compared to £7,463 million at 31 March 2001.

Summary

This has been a difficult year for ScottishPower with the results for the first six months including additional excess power costs incurred in the US. Results in the second six months of the year to March 2002 have improved and earnings per share for that period were 45% higher than the same period last year. With proceeds from the Southern Water disposal in April 2002, ScottishPower’s balance sheet is also stronger with gearing reduced.

By:
	Finance Director

1 May 2002

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BOARD OF DIRECTORS & EXECUTIVE TEAM

Executive Directors

Ian Russell (49) is Chief Executive, having been appointed to this position in April 2001. He joined ScottishPower as Finance Director in April 1994, and became Deputy Chief Executive in November 1998. He is a member of the Institute of Chartered Accountants of Scotland, having trained with Thomson McLintock, and has held senior finance positions with Tomkins plc and HSBC. He has a B.Com (Hons) from the University of Edinburgh.

Charles Berry (50) is Executive Director UK, responsible in this capacity for the UK energy businesses of Generation, Trading and Supply as well as regulatory matters. He joined ScottishPower in November 1991, and was appointed to the Board in April 1999. He is non-executive Chairman of Thus Group plc. Before joining ScottishPower, he was Group Development Director of Norwest Holst, a subsidiary of Compagnie Générale des Eaux, and prior to that held management positions within subsidiaries of Pilkington plc. He holds a BSc (First Class Hons) in Electrical Engineering from the University of Glasgow and a Masters Degree in Management from the Massachusetts Institute of Technology.

David Nish (41) is Finance Director, having joined ScottishPower in September 1997 as Deputy Finance Director and then being appointed to the Board as Finance Director in December 1999. In this capacity, he also has responsibility at Board level for performance management and information technology. He is a non-executive director of Thus Group plc. He is a member of the Institute of Chartered Accountants of Scotland and its Qualifications Board, a non-executive director of Scottish Knowledge plc and a member of the Scottish Council of the CBI. Prior to joining ScottishPower, he was a partner with Price Waterhouse. He has a B.Acc from the University of Glasgow.

Non-executive Directors

Charles Miller Smith (62) joined the Board as Deputy Chairman in August 1999 and was appointed Chairman in April 2000. Following a career with Unilever for some 30 years, during the last five of which he was Director of Finance and latterly of the Food Executive, he was appointed Chief Executive of ICI in 1995 and then served as Chairman from 1999 to December 2001. He is an adviser to Goldman Sachs, a non-executive director of The Royal Scottish National Orchestra and a member of the Court of Governors of Henley Management College.

Euan Baird (64) joined the Board in January 2001 and is Chairman and Chief Executive Officer of Schlumberger Limited. He joined Schlumberger in 1960 and held various positions worldwide before taking up his present position in 1986. He is currently a trustee of Tocqueville Alexis Trust and Carnegie Institution of Washington, and a member of the Comité National de la Science in France and the Prime Minister’s Council of Science and Technology in the UK. He is a non-executive director of Société Générale and Areva. His current term of office will expire at the AGM in 2004.

Mair Barnes (57) joined the Board in April 1998. She is a non-executive director of Patientline plc, Littlewoods plc and the South African company, Woolworths Holdings Limited. She has also been a non-executive member of the Departmental Board of the Department of Trade and Industry (“DTI”) and continues to serve as a member of the DTI’s Strategy Board and Services Group Board. She was previously Managing Director of Woolworths plc in the UK until 1994, and subsequently she became Chairman of Vantios plc until 1998. She was also formerly a non-executive director of George Wimpey plc and Abbey National plc. Her current term of office will expire at the AGM in 2004.

Philip Carroll (64) joined the Board in January 2002. He was formerly Chairman and Chief Executive Officer of Fluor Corporation, a California-based international engineering, construction and services company, until his retirement in February 2002. Previously, he was with Shell Oil for over 35 years, serving as President and Chief Executive Officer from 1993 to 1998. He is an honorary life member of the Board of the American Petroleum Institute and holds various posts with the James A Baker III Institute for Public Policy of Rice University and the University of Houston. His current term of office, subject to his election in 2002, will expire at the AGM in 2005.

Sir Peter Gregson GCB (65) joined the Board in December 1996 and is the company’s senior independent non-executive director and Chairman of the Remuneration Committee. He was formerly a career civil servant, having served latterly as Permanent Secretary of the Department of Energy from 1985 to 1989 and Permanent Secretary of the Department of Trade and Industry until his retirement in June 1996. He is Deputy Chairman of the Board of Companions of the Institute of Management and was previously a non-executive director of Woolwich plc. His current term of office, subject to his re-election in 2002, will expire at the AGM in 2003.

        Nolan Karras (57) joined the Board in November 1999. He continues as a director of PacifiCorp, having previously (until the merger in November 1999) served as Chairman of the PacifiCorp Personnel Committee. He is President of The Karras Company, Inc., and a Registered Principal for Raymond James Financial Services. He is Chief Executive Officer of Western Hay Company, Inc., and a non-executive director of Beneficial Life Insurance Company. He is a member of the Utah State Higher Education Board of Regents and serves on the board of Ogden-Weber Applied Technology College. He also served as a member of the Utah House of Representatives from 1981 to 1990, and as Speaker of the Utah House of Representatives from 1989 to 1990. His current term of office, subject to his re-election in 2002, will expire at the AGM in 2003.

Ewen Macpherson (60) joined the Board in September 1996 and is Chairman of the Audit Committee. He had a long career with 3i Group plc, leading to his appointment as Chief Executive from 1992 until his retirement in 1997. He is Chairman of Merrill Lynch New Energy Technology plc and a non-executive director of Foreign & Colonial Investment Trust plc and Pantheon International Participations plc. He is also Chairman of the Trustees of GlaxoSmithKline Pension Fund. Previous appointments include non-executive directorships of M&G Group plc, Booker plc and The Law Debenture Corporation plc. His current term of office will expire at the AGM in 2003.

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Executive Team

The Executive Team is a primary committee of the Board and includes not only the Executive Directors of the Board but also the following key Executives and Officers from the group:

Julian Brown (52) was appointed Group Director, Strategy in April 1997, having joined ScottishPower in 1993. He began his commercial career with Exxon Chemical in Australia and subsequently spent seven years with management consultants McKinsey and Company. He holds a BSc from the Australian National University and a PhD in Chemistry from University College London.

Dominic Fry (42) joined ScottishPower in September 2000 as Group Director, Corporate Communications. He is responsible for investor and media relations, communications with employees and managing the group’s overall reputation. He has held appointments as Communications Director with J Sainsbury plc and Eurotunnel. He chairs the Trading Board of the Glasgow Science Centre and is a communications adviser to the Royal Shakespeare Company and Business in the Community’s Rural Action programme. He was educated at the Université Paul Valéry III in Montpellier and the University of North Carolina.

Terry Hudgens (47) was appointed Chief Executive Officer of ScottishPower’s competitive US energy business PacifiCorp Power Marketing, Inc., in December 2001 and, at the same time, joined the Executive Team. He joined PacifiCorp as Senior Vice President of Power Supply in April 2000, having previously spent 25 years with Texaco Inc. He was formerly President of Texaco Natural Gas and served as Texaco’s senior representative and elected officer in the Natural Gas Supply Association. He has a bachelor’s degree in civil engineering from the University of Houston.

Judi Johansen (43) was appointed President & Chief Executive Officer of PacifiCorp in June 2001 and joined the Executive Team in December 2001. She is responsible for the company’s mining operations, regulated power generation facilities, wholesale energy services, transmission, distribution and supply. She joined PacifiCorp as Executive Vice President of Regulation and External Affairs in December 2000, having held senior positions with the Bonneville Power Administration and Washington Water Power. She is involved in several civic and professional activities. She has a bachelor’s degree in political science from Colorado State University and a law degree from Northwestern School of Law at Lewis & Clark College in Portland, Oregon.

Ronnie Mercer (58) was appointed Group Director, Infrastructure in April 2001 and is responsible in this role for the UK wires business and, prior to its sale, Southern Water. He joined the ScottishPower Generation Business in 1994 and was appointed Generation Director in 1996 and then Managing Director of Southern Water in 1998. Previous career positions include Scottish Director and Managing Director roles in British Steel. He was educated at Paisley College of Technology.

Andrew Mitchell (50) was appointed Group Company Secretary in July 1993 and is responsible in this role for corporate governance, compliance and reporting and shareholder services. He also serves as Chairman of the trustees of the group’s UK pension schemes. Prior to joining ScottishPower, he held a number of company secretarial appointments, latterly as Company Secretary of The Laird Group plc and then Stakis plc, now part of the Hilton Group. He is a graduate in law from the University of Edinburgh (LLB Hons) and the London School of Economics (LLM) and is a member of the Institute of Chartered Secretaries and Administrators.

Michael Pittman (49) was appointed Group Director, Human Resources in November 2001. He has groupwide responsibility for Human Resources, leading the focus on talent management, one of the group’s main strategic thrusts. He joined PacifiCorp in December 1979 and was appointed to the PacifiCorp Board in May 2000. He chairs the PacifiCorp Foundation for Learning Board and is involved in numerous civic activities. He has held several positions within PacifiCorp, including safety and health, risk management, and operations. He holds an advanced degree in environmental health from the University of Washington.

James Stanley (47) was appointed Group Director, Commercial and Legal in March 1996. He is responsible in this role for the provision of all legal, commercial and associated services throughout the group and particularly the delivery of M&A projects. In his early career he specialised in commercial litigation in private practice. In 1986 he moved to the Trafalgar House Group and subsequently became both Commercial Director of John Brown plc and General Counsel to the Global Engineering Division of the Group. He is a graduate in law from Nottingham University and the College of Law in Chester where he qualified as a solicitor in 1980.

Members of the Audit Committee

Ewen Macpherson, Chairman

Philip Carroll

Sir Peter Gregson

Charles Miller Smith

Members of the Nomination Committee

Charles Miller Smith, Chairman

Mair Barnes

Sir Peter Gregson

Nolan Karras

Ian Russell

Members of the Remuneration Committee

Sir Peter Gregson, Chairman

Euan Baird

Mair Barnes

Nolan Karras

Ewen Macpherson

Members of the Executive Team

Ian Russell

Charles Berry

David Nish

Julian Brown

Dominic Fry

Terry Hudgens

Judi Johansen

Ronnie Mercer

Andrew Mitchell

Michael Pittman

James Stanley

Board changes

Ian Russell succeeded Sir Ian Robinson as Chief Executive on 17 April 2001. Sir Ian Robinson retired from the Board on 4 May 2001; Keith McKennon and John Parnaby following the conclusion of last year’s Annual General Meeting on 27 July 2001; and Alan Richardson and Ken Vowles on 31 December 2001 and 31 March 2002, respectively. Robert Miller resigned from the Board on 8 June 2001. Allan Leighton served on the Board throughout the year but resigns with effect from 12 June 2002. Philip Carroll was appointed to the Board on 15 January 2002 and, in accordance with the Articles of Association, he will retire from office at the Annual General Meeting and, being eligible, offers himself for election. In addition, Charles Berry, Sir Peter Gregson and Nolan Karras retire by rotation and, being eligible, offer themselves for re-election. Charles Berry has a service contract terminable by either party upon one year’s notice.

For the purposes of the Annual Report on Form 20-F, the members of the Executive Team are regarded as Officers of the company.

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CORPORATE GOVERNANCE

Corporate governance statement

The Company is committed to the highest standards of corporate governance. This statement, together with the Remuneration Report of the Directors, set out on pages 48 to 54, describes how, in respect of the financial year ended 31 March 2002, the company has been in compliance with the principles of good governance set out by the Listing Rules of the Financial Services Authority in Section 1 of the Combined Code.

Board of directors

There is a well-established division of authority and responsibility at the most senior level within the company through the separation of the roles of Chairman and Chief Executive. There are currently three executive and seven non-executive directors (including a non-executive Chairman) on the Board. Sir Peter Gregson is the senior independent non-executive director. With the exception of the Chairman, all non-executive directors are considered by the Board to be independent.

The non-executive directors are from varied business and other backgrounds, and all directors have the benefit of induction visits and briefings following their appointment to the Board. Their experience allows them to exercise independent judgement on the Board and their views carry substantial weight in Board decisions. They contribute to the company’s strategy and policy formulation, in addition to monitoring its performance and its executive management. The non-executive directors are appointed for a specified term; reappointment is not automatic, and each non-executive director’s position is subject to review prior to the expiry of his or her term of office.

The Board meets on a regular basis and has a schedule of matters concerning key aspects of the company’s activities which are reserved to the Board for decision. The Board exercises full control over strategy, investment and capital expenditure. In addition, individual executive directors have specific responsibilities for such matters as health, safety, environment and regulation. All directors have access to the Company Secretary, who is responsible for ensuring that all Board procedures are observed. Any director wishing to do so, in furtherance of his or her duties, may take independent professional advice at the company’s expense.

Board committees

The Board has four principal standing committees: namely, the Audit Committee, Nomination Committee, Remuneration Committee and the Executive Team. The composition, purpose and function of each of these committees are described below.

Audit Committee

The Audit Committee is comprised of non-executive directors only and has been chaired by Ewen Macpherson since July 2001. A majority of the members are independent. It has a remit to review the company’s accounting policies, internal control and financial reporting and makes recommendations on these matters to the Board fo decision. It also considers the appointment and fees of the external auditors.

Nomination Committee

The Nomination Committee is chaired by the Chairman of the Board with, as members of the Committee, the Chief Executive and three independent non-executive directors. It has a remit to consider and make recommendations to the Board on all new appointments of directors, having regard to the overall balance and composition of the Board; to consider and approve the remit and responsibilities of the executive directors; and to review and advise upon issues of succession planning and organisational development.

Remuneration Committee

The Remuneration Committee is comprised of independent non-executive directors only and has been chaired by Sir Peter Gregson since July 2001. It has a remit to consider and make recommendations on Board remuneration policy and, on behalf of the Board, to determine specific remuneration packages for each of the executive directors. In discharging its remit, the Committee has regard to the provisions of the Combined Code and has as an objective the aim of providing packages to attract, retain and motivate executive directors of the quality required; to judge the company’s position in matters of remuneration policy and practice relative to other companies; and to take into account wider issues of pay-setting. It also has responsibility for the company’s bonus and incentive schemes. The Remuneration Report of the Directors for 2001/02 is set out on pages 48 to 54.

Executive Team

        The Executive Team comprises the Chief Executive and other executive directors, together with the Group Director, Strategy; Group Director, Corporate Communications; Chief Executive Officer, PacifiCorp Power Marketing, Inc.; Chief Executive Officer, PacifiCorp; Group Director, Infrastructure; Group Director, Human Resources; Group Director, Commercial and Legal; and the Group Company Secretary. Operational control and implementation of group strategy and policy are responsibilities delegated by the Board to the Chief Executive, who is supported by the Executive Team (and by divisional and business boards) in the discharge of these functions. Major issues and decisions are reported to the Board.

Internal control

The directors of ScottishPower have overall responsibility for the system of internal controls and for reviewing the effectiveness of the system. The system of internal controls is designed to manage rather than eliminate the risk of failure to achieve business objectives. In pursuing these objectives, internal control can only provide reasonable and not absolute assurance against material misstatement or loss.

A Group Risk Management Committee (“GRMC”), comprising of members of the Executive Team, has been established to assist the Board in ensuring that an appropriate risk and control governance framework is in place. The GRMC meets monthly and the key responsibilities of this group are to implement the risk management strategy; to ensure that an appropriate risk management framework is operating effectively across the company; to embed a risk culture throughout the group; and to provide the Executive Team, the Audit Committee and the Board with a consolidated view of the risk profile of the company identifying any major exposures and mitigating actions.

The risk management framework and internal control system across the group, which is subject to continuous development, provides the basis on which the company has complied with the Combined Code provisions on internal control.

Control environment

The company is committed to ensuring that a proper control environment is maintained. There is a commitment to competence and integrity, and to the communication of ethical values and control consciousness to managers and employees. Human Resources policies underpin that commitment by a focus on enhancing job skills and promoting high standards of probity among staff. In addition, the appropriate organisational structure has been developed within which to control the businesses and to delegate authority and accountability, having regard to acceptable levels of risk.

Identification and evaluation of risks and control objectives

The company’s strategy is to follow an appropriate risk policy, which effectively manages exposures related to the achievement of business objectives.

Each business identifies and assesses the key business risks associated with the achievement of its strategic objectives. Any key actions needed to further enhance the

46

control environment are identified along with the person responsible for the management of the specific risk. Each month a detailed review of the key risks, controls and action plans within each of the businesses takes place and a Risk Report is produced for review and challenge by the board of each business. This monthly Risk Report is a standing item on the agenda of the business boards, which operate throughout the group. This is a key tool in ensuring the active management of risk across the organisation.

Business Controls Managers have been appointed within each of the businesses to help ensure that the risk management and internal control system is consistently adopted, updated and embedded into the business processes.

The corporate centre also considers those risks to the group’s strategic objectives that may not be identified and managed at a business level.

The GRMC on a monthly basis receives the group-wide Risk Report together with supporting documentation for review. This report highlights the most significant risks across the group, the actions being taken to mitigate these and also identified individuals responsible for the management of these risks. The information being supplied to the GRMC is continually being developed to include quantitative measures such as sensitivity analyses and Value-at-risk calculations for issues reported on the Group Energy Risk Report.

The use of a well-defined risk management methodology across all businesses allows a consistent and co-ordinated approach to risk reporting for review by the Board, which also receives regular reports on these matters from the Audit Committee, to enable the directors to review the effectiveness of the system of internal controls on a regular basis.

A key element and requirement of the risk evaluation process is that a written certificate is provided twice per year by the Managing Director of each business confirming that they have reviewed the effectiveness of the system of internal controls during the year.

Energy trading

In light of the volatility experienced in the western US power market a number of enhancements have been implemented to the risk and control framework to further strengthen the process for identification, assessment and mitigation of risks in the energy trading market. The key changes in this area include the enhancement of systems and business processes as well as the appointment of an Energy Risk Director who sits on the energy and group risk committees. The key responsibilities of the energy risk committees are to ensure that all risks pertaining to operating the trading and energy businesses are understood, quantified, managed and reported on a consistent basis across the group.

Monitoring and corrective action

The Executive Team reviews monthly the key risks facing the group and the controls and monitoring procedures for these. Operation of the group’s control and monitoring procedures is reviewed and tested by the group’s internal audit function under the supervision of the Director of Internal Audit, reporting to the Finance Director and with access to the Chairman of the Audit Committee. Internal audit reports and recommendations on the group’s procedures are reviewed regularly by the Audit Committee. As part of their external audit responsibilities, the external auditors also provide reports to the Audit Committee on the operation of the group’s internal financial control procedures. The Audit Committee also receives regular reports on the continued development, implementation and evaluation of the risk management and internal control system.

Auditor independence

The Audit Committee and the firm of external auditors have safeguards to avoid the possibility that the auditors’ objectivity and independence could be compromised. These safeguards include the auditors’ report to the directors and the Audit Committee on the actions they take to comply with the professional and regulatory requirements and best practice designed to ensure their independence from ScottishPower.

Where it is deemed that the work to be undertaken is of a nature that is generally considered reasonable to be completed by the auditor of the group for sound commercial and practical reasons, including confidentiality, the conduct of such work will be permissible. Examples of work that would fall into this category include the completion of regulatory audits, provision of regulatory advice, reporting to the SEC and the UK Listing Authority and the completion of financial due diligence work.

With regard to the provision of taxation services, including verification, compliance and tax planning opportunities, where the Board believes they are best suited, the firm of external auditors will be used.

This policy, which was approved by the Audit Committee and the Board, came into effect on 1 May 2002 and specifically prevents the use of the firm of external auditors from undertaking general consultancy work on behalf of the group.

Social, environmental and ethical risks and opportunities

As a part of the internal control framework, the Board takes regular account of the significance of social, environmental and ethical (“SEE”) matters to the business of the company. The Board receives full information on SEE matters and these issues are included in the training offered to directors on their first appointment. This allows the Board to identify the risks and opportunities arising from the impact of SEE issues on the company’s short- and long-term value.

Further information regarding the SEE policies and practices of the company can be found in the separate Corporate Environment Sustainability and Community Reports.

Political donations and expenditure

In previous Annual Reports, it has been the company’s practice to state that no money has been given by the company for political purposes. This policy has not changed: ScottishPower remains a politically neutral organisation. However, as was outlined to shareholders at last year’s Annual General Meeting, the company is now subject to new rules governing political donations and expenditure by virtue of the Political Parties, Elections and Referendums Act 2000, which came into force on 16 February 2001. This new legislation defines political “donations” and “expenditure” in wider terms than would be commonly understood by these phrases. The definitions include expenditure which the Board believes it is in the interests of the company to incur. The new Act also requires companies to obtain prior shareholder approval of this expenditure and, at the Annual General Meeting in 2001, the company obtained authorisation up to a maximum amount of £100,000.

During the financial year ended 31 March 2002, the company paid a total of £13,000 for activities which may be regarded as falling within the terms of the new Act. These activities comprised sponsorship of briefings, receptions and fringe meetings at the Labour, Conservative and Scottish National Party Conferences and support for other party functions. These occasions present an important opportunity for the company to represent its views on a non-partisan basis to politicians from across the political spectrum. The payments made do not indicate support, and are not intended to influence support, for any particular political party.

In addition, the company paid £36,000 in connection with related activities such as participation in fuel poverty forums and in the promotion of sustainable energy.

The Board believes that participation in these events is in the best interests of the company.

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REMUNERATION REPORT OF THE DIRECTORS

Introduction

The following statement sets out how, during the financial year ended 31 March 2002, the company has been in compliance with the remuneration principles set out in Part B of the Combined Code. The statement also takes account of the proposals for reform of remuneration disclosure contained in the Department of Trade and Industry Consultative Document on Directors’ Remuneration of December 2001.

Consideration of remuneration matters by the directors

The ScottishPower Board is responsible for determining the remuneration policy for the ScottishPower group. The Remuneration Committee determines the detail of remuneration arrangements for executive directors and reviews proposals in respect of other senior executives. The relationship between the Board and the Committee is governed by formal Terms of Reference, which are regularly reviewed and reflect best practice in this field.

The Remuneration Committee consists solely of independent non-executive directors. Its members are Sir Peter Gregson (Chairman), Euan Baird, Mair Barnes, Nolan Karras and Ewen Macpherson. These members have no personal financial interest, other than as shareholders, in the matters considered by the Committee. They are paid a fee and expenses, but do not receive any other remuneration from the company. Details of the payments made to all non-executive directors are set out in Table 26 (page51).

The Terms of Reference require the Chairman of the Committee to attend the Annual General Meeting in order to account to shareholders for the decisions of the Committee.

The Chairman of the company, Charles Miller Smith, and the Chief Executive, Ian Russell, are generally invited to attend meetings and advise, as appropriate, on the performance of executive directors. They are not, however, present during any discussion of their own remuneration. The Terms of Reference contain conflict of interest provisions to ensure that no directors are involved in any decision relating to their own remuneration.

The Committee is advised internally by the Group Company Secretary, Andrew Mitchell (who acts as Secretary to the Committee), the Group Director, Human Resources, Michael Pittman, and the Director, Group Remuneration & Benefits, James McInally. The Committee is also provided with independent advice from external remuneration consultants, principally Monks Partnership. The Terms of Reference empower the Committee to avail itself of external legal and professional advice at the expense of the company.

During the year, the Board accepted all of the recommendations from the Committee without significant amendment.

Following the flotation of Thus plc in November 1999, and in accordance with good corporate governance principles, the Thus Board established a separate Remuneration Committee which determines the details of remuneration arrangements for that company. The entire shareholding of ScottishPower in Thus Group plc was demerged to ScottishPower shareholders on 19 March 2002.

Statement of remuneration policy

Philosophy and policy

ScottishPower seeks to ensure that remuneration and incentive schemes are in line with best practice and promote the interests of shareholders.

Rewards for executives and directors should attract and retain individuals of high quality, who have the requisite skills and are incentivised to achieve performance which exceeds that of competitor companies. As such, remuneration packages must be market-competitive. All senior management remuneration packages are set according to a mid-market position, with packages above the mid-market level provided only where supported by demonstrably superior personal performance. As the company evolves, remuneration packages will be developed to reflect the prevailing market practice in each business environment.

Annual bonus arrangements have been structured so that targets reflect corporate, business unit and individual performance.

The company operates a Personal Shareholding Policy, requiring executives and senior managers to build-up and retain a shareholding in the company in proportion to their annual salaries. These proportions are three times salary for the Chief Executive and two times salary for other executive directors. The Committee considers this policy to be in the best interests of shareholders.

The Committee takes a balanced view of remuneration, considering each element relative to market and, in the past, has realigned elements of the package to reflect market conditions or changes in market practice.

Practical application

In setting remuneration levels, the Committee commissioned an independent evaluation of the roles of the executive, and also of the next levels of management within the company. The Committee has also continued to take independent advice from external remuneration consultants on market-level remuneration, based on comparison with companies of similar size and complexity. In considering the comparator companies, the consultants have included a number of other utilities but have not restricted their study solely to utilities.

Base salaries

The Committee sets the base salary for each executive director by reference to individual performance through a formal appraisal system, and to external market data, based on job evaluation principles and reflecting similar roles in other comparable companies.

    Annual performance-related bonus

Executive directors and senior management participate in the company’s performance-related pay schemes. All payments under the schemes are non-pensionable and are subject to the approval of the Committee.

The 2001/02 scheme for executive directors provided a bonus opportunity of a maximum of 75% of salary, with half determined by the company’s financial performance. The balance of the bonus is linked to each executive’s achievement of key strategic objectives, both short-term and long-term. Objectives are set annually by the Board and performance against these is reviewed on a six-monthly basis.

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For the 2001/02 performance year, the executive directors indicated that they did not wish to be considered for a bonus payment, despite the fact that their personal performance and achievement of strategic objectives would have warranted such a payment under the rules of the Plan. The Committee decided that no bonus should be paid to executive directors.

Executive share schemes

The company operates a performance share plan, the Long Term Incentive Plan (“LTIP”), and an Executive Share Option Plan 2001 (“ExSOP”) for executive directors and other senior managers.

The LTIP links the rewards closely between management and shareholders, and focuses on long-term corporate performance. Under the current LTIP, awards to acquire shares in ScottishPower at nil or nominal cost are made to the participants up to a maximum value equal to 75% of base salary. The award will vest only if the Committee is satisfied that certain gateway performance measures are met. These relate to the sustained underlying financial performance of the company and performance in relation to customer service standards, including those set by Ofgem and OFWAT.

The number of shares which actually vest is dependent upon the company’s comparative total shareholder return performance, over a three-year performance period. For LTIP awards which have vested during the year, this performance is measured against that of the FTSE 100 index and an index of the Electricity and Water sectors of the FTSE All Share Index. For LTIP awards granted during the year, this performance is measured against a comparator group of 40 international energy companies, as identified below:

AES Corp; American Electric Power Inc; Calpine Corp; Centrica; Chubu Electric Power Co Inc; CLP Holdings Limited; Constellation Energy Group Inc; Dominion Resources Inc; Duke Energy Corp; Dynegy Inc; Edison SpA; Edison International; El Paso Corp; Electricidade de Portugal SA; Electrabel SA; Endesa SA; Enron; Ente Nazionale per l’Energia Elettrica SpA (Enel); Entergy Corp; Exelon; FirstEnergy Corp; FPL Group Inc; Gas Natural SDG SA; Iberdrola SA; Kansai Electric Power Co Inc; Lattice Group plc; National Grid; Powergen; PPL Corp; Progress Energy Inc; Public Service Enterprise Group Inc; Reliant Energy Inc; Scottish & Southern Energy; Southern Company Inc; Tenaga Nasional Bhd; The Tokyo Electric Power Co Inc; TXU; Union Fenosa; Williams Companies Inc; Xcel Energy Inc.

No shares vest unless the company’s performance is at least equal to the median performance of the comparator group. 100% of the shares vest if the company’s performance is equal to or exceeds the top quartile. The number of shares that vest for performance between these two points is determined on a straight-line basis.

During the 2001/02 year, the company introduced a new ExSOP. Options granted under the ExSOP are subject to the performance criterion that the percentage increase in the company’s annualised earnings per share be at least 3% (adjusted for any increase in the Retail Price Index). This criterion is assessed at the end of the third financial year, the first year being the financial year starting immediately before the date of grant. If the criterion is not satisfied over this period it is tested again at the end of the fourth financial year. If the criterion is not satisfied over this period it is tested again at the end of the fifth financial year. If the criterion is not satisfied over this period then the options lapse.

A number of legacy share-based incentive plans are also in place in the company’s international operations. These are structured to comply with local tax and legislation and are established at market-competitive levels. No executive director participates in any international share incentive arrangement and no further grants will be made under these plans.

Employee Share Plans

The company operates a savings-related share option scheme, which is open to all UK permanent employees. Under this scheme, options are granted over ScottishPower shares at a discount of 20% from the prevailing market price at the time of grant to eligible employees who agree to save up to £250 per month over a period of three or five years.

In addition, the Government implemented legislation in July 2000 to enable companies to introduce a new Inland Revenue approved Employee Share Ownership Plan (“ESOP”). The company was amongst the first to introduce these arrangements for all UK employees. The ESOP enables employees to purchase shares in the company from pre-tax income up to the limits specified in the legislation. The company matches these shares at no cost to the employee on a one-for-one ratio. The legislation also enables the company to award free shares to employees. No free shares were awarded during 2001/02.

Pension

The executive directors, and other senior managers of the company, are provided

The graphs below represent the comparative Total Shareholder Return (% growth) performance of the company during the performance period for Award 3 of the Long Term Incentive Plan (May 1998 — May 2001) that vested during the financial year.

[GRAPH APPEARS HERE]

[GRAPH APPEARS HERE]

49

with pension benefits through the company’s main pension scheme, and through an executive top-up pension plan which provides a maximum pension of two-thirds of final salary on retirement at age 63, reduced where service to age 63 is less than 20 years. Pensionable salary is normally base salary in the 12 months prior to leaving the company.

Individuals who joined the company on or after 1 June 1989 are subject to the Inland Revenue earnings cap, introduced by the Finance Act 1989. Entitlement above the cap cannot be provided through the company’s approved pension benefits, and therefore arrangements on an unapproved basis have been made to provide total benefits for executives affected by the legislation as though there was no cap. The total liability in respect of executives and senior employees arising in relation to unapproved benefits accrued for service for the year to 31 March 2002 was £690,000. The Trustee body of the Executive Top Up Plan is chaired by the Group Company Secretary.

The Committee has reported the pension expense in accordance with the requirements of the UK Listing Authority. Pension costs detailed in the Accounts are calculated as the cost of providing benefits accrued in 2001/02.

Benefits

Executive directors are eligible for a range of benefits on which they are assessed for tax. These include the provision of a company car, fuel, private medical provision and permanent health insurance. Senior executives, depending upon grade, are eligible for certain of these benefits.

As with salary, the level of benefits is reviewed annually through surveys from independent consultants. Practice varies as to the composition of these items amongst the comparator group and the company’s benefits are broadly in line with the practice of the group.

To summarise the above, the executive directors are required to meet or exceed performance targets in order to receive bonus payments and to participate in the Long Term Incentive Plan and the Executive Share Option Plan 2001. Their base salaries are set in accordance with market competitive levels and performance assessments. The employee share plans are open to all UK employees. They are essentially savings vehicles and are not subject to a performance test. Pension entitlements and other benefits are not performance related.

Service contracts

ScottishPower has reviewed its policy on service contracts and, in accordance with the best practice recommendation of the Combined Code, has resolved that new appointees to the Board be offered notice periods of one year. The Committee recognises however that it may be necessary, in the case of appointments from outside the company, to offer a longer initial notice period: the intent being to subsequently reduce this period to one year following an agreed initial period.

The Committee’s policy on early termination is to emphasise the duty to mitigate to the fullest extent practicable. Senior managers within the company have notice periods ranging from six months to one year.

Executive directors, Charles Berry and David Nish, were appointed to the Board on or after 1 April 1999; these appointments have service contracts terminable on one year’s notice from both parties.

Two executive directors appointed before 1 April 1999 had service contracts terminable by the company on two years’ notice (this having been reduced from the three year period applicable prior to September 1994) and by the individuals concerned on one year’s notice. Ken Vowles retired on 31 March 2002 and accordingly only one executive director, the Chief Executive, Ian Russell, now has a service contract terminable by the company on two years’ notice. Given that the Chief Executive agreed, without compensation, to a previous reduction in the notice period in his service contract, the Committee believes that it remains appropriate for him to retain a two-year rolling contract.

External non-executive appointments

The company encourages its directors to become non-executive directors of other companies, provided that these are not with competing companies, are not likely to lead to any conflicts of interest, and do not require extensive commitments of time which would prejudice their roles within the company. This serves to add to their personal and professional experience and knowledge, to the benefit of the company. Any fees derived from such appointments may be retained by the executives.

Remuneration policy for non-executive directors

The remuneration of non-executive directors is determined by the Board and consists of fees for their service in connection with the Board and Board Committees. Additional fees are also payable for chairing Board Committees. The non-executive directors do not have service contracts, are not members of the company’s pension schemes and do not participate in any bonus, share option or other profit or long-term incentive scheme. Full details of the remuneration of the non-executive directors are contained in Table 26.

Compensation of directors and officers

For US reporting purposes, it is necessary to provide information on compensation and interests for directors and officers. The aggregate amount of compensation paid by the group to all directors and officers of the company was £5,482,058.

During 2001/02 the aggregate amount set aside or accrued by the group to provide pension, retirement or similar benefits for directors and officers of the company pursuant to any existing plan provided or contributed to by the group was £1,740,336.

Interest of management in certain transactions

There have been no material transactions during the group’s three most recent financial years, nor are there presently proposed to be any material transactions to which the company or any of its subsidiaries was or is a party and in which any director or officer, or 10% shareholder, or any relative or spouse thereof or any relative of such a spouse, who had the same home as such person or who is a director or officer of any subsidiary of the company has or is to have a direct or indirect material interest.

During the group’s three most recent financial years there has been no, and at present there is no, outstanding indebtedness to the company or any of its subsidiaries owed or owing by any director or officer of the group or any associate thereof.

50

Directors’ interests

Other than as disclosed, none of the directors had a material interest in any contract of significance with the company and its subsidiaries during or at the end of the financial year. The directors’ interests, all beneficial, in the ordinary shares of the company, including interests in options under the company’s ExSOP and Sharesave Schemes and awards under the LTIP, are shown on pages 52 to 54.

Directors’ and officers’ liability insurance

The company maintains liability insurance for the directors and officers of the company and its subsidiaries.

Directors’ emoluments and interests

Total emoluments

Table 26 provides a breakdown of the total emoluments of the Chairman and all the directors in office during the year ended 31 March 2002.

Directors’ pension benefits

Details of pension benefits earned by the executive directors during the year are shown in Table 27.

Table 26—Remuneration of directors during 2001/02

	Basic salary £000’s		Bonus £000’s		Benefits in kind £000’s		Total £000’s
	2002	2001	2002	2001	2002	2001	2002	2001
Chairman and executive directors
Charles Miller Smith	235.0	235.0	—	—	13.8	4.7	248.8	239.7
Sir Ian Robinson (retired 4 May 2001)	93.3	522.7	—	—	2.9	24.2	96.2	546.9
Ian Russell (appointed Chief Executive 17 April 2001)	542.9	390.0	—	—	27.6	34.6	570.5	424.6
Charles Berry	280.0	220.0	—	—	19.2	19.3	299.2	239.3
David Nish	325.0	225.0	—	—	23.9	28.0	348.9	253.0
Alan Richardson (retired 31 December 2001)*	225.0	245.0	—	—	0.8	0.7	225.8	245.7
Ken Vowles (retired 31 March 2002)	300.0	270.0	—	—	16.0	14.1	316.0	284.1
Total	2,001.2	2,107.7	—	—	104.2	125.6	2,105.4	2,233.3

	Fees £000’s		Bonus £000’s		Benefits in kind £000’s		Total £000’s
	2002	2001	2002	2001	2002	2001	2002	2001
Non-executive directors (fees & expenses)
Keith McKennon (retired 27 July 2001)	21.3	64.0	—	—	17.4	11.0	38.7	75.0
Euan Baird	28.5	6.5	—	—	0.7	—	29.2	6.5
Mair Barnes	32.0	33.0	—	—	1.0	2.8	33.0	35.8
Philip Carroll (appointed 15 January 2002)	4.4	—	—	—	0.6	—	5.0	—
Sir Peter Gregson	40.5	36.5	—	—	2.8	2.1	43.3	38.6
Nolan Karras**	32.8	33.5	—	—	19.7	6.5	52.5	40.0
Allan Leighton	27.5	6.5	—	—	0.1	0.4	27.6	6.9
Ewen Macpherson	39.5	39.5	—	—	4.0	2.2	43.5	41.7
Robert Miller (resigned 8 June 2001)	6.1	31.5	—	—	2.2	21.0	8.3	52.5
John Parnaby (retired 27 July 2001)	12.8	40.5	—	—	3.9	1.9	16.7	42.4
Total	245.4	291.5	—	—	52.4	47.9	297.8	339.4

Other emoluments

* Alan Richardson received an additional £381,220 (2001 £283,220) in respect of housing, foreign service allowance and other essential costs associated with his assignment as Executive Director, US, based in Portland, Oregon. These costs include relocation and repatriation back to the UK.

** Nolan Karras received emoluments in the US of £22,613 (2001 £26,857) in respect of services to the PacifiCorp and Utah advisory boards in the form of cash and shares.

(i) The emoluments of the highest paid director (Ian Russell) excluding pension contributions were £570,531. In addition, gains on exercise of share awards before tax during the year by Ian Russell amounted to £138,628. The emoluments of the highest paid director in 2000/01 (Sir Ian Robinson) excluding pension contributions were £546,862. Details of other share related incentives are contained in Tables 28 and 29.

(ii) Pension contributions made by the company under approved pension arrangements for Ian Russell amounted to £nil (2001 £nil). Ian Russell also has an entitlement under the unapproved pension benefits described further in Table 27(i).

(iii) Sir Ian Robinson retired from the Board on 4 May 2001 and as an employee on 31 May 2001. Alan Richardson retired from the Board and as an employee on 31December 2001. Ken Vowles retired from the Board and as an employee on 31 March 2002.

(iv) In addition to the above, payments were made to Sir Ian Robinson of £385,000; Alan Richardson of £372,099; and Ken Vowles of £405,649, in accordance with the terms of their respective contracts. Details of pension scheme entitlements and interests in performance and other share plans are set out overleaf in Tables 27 and 29 respectively.

51

Table 27—Defined benefits pension scheme 2001/02

	Transferred -in benefits £ p.a.	Additional Pension earned in year £ p.a.	Accrued entitlement £ p.a.	Transfer value of increases after indexation (net of director’s Contribution) £ p.a.
Charles Miller Smith	—	—	—	—
Sir Ian Robinson (retired from the Board on 4 May 2001 and from the company on 31 May 2001)	—	—	—	—
Ian Russell	15,094	52,738	144,159	545,011
Charles Berry	—	23,568	82,744	246,993
David Nish	34,938	26,111	67,356	200,946
Alan Richardson (retired 31 December 2001)	—	50,263	130,000	633,959
Ken Vowles (retired 31 March 2002)	127,808	14,346	141,570	231,657

(i) The accrued entitlement of the highest paid director (Ian Russell) was £144,159. In 2001, the accrued entitlement of the highest paid director (Sir Ian Robinson) was £319,200. During the year, retirement benefits were accrued under the defined benefits pension scheme in respect of 5 directors (2001 6 directors). The method of calculation of retirement benefits for Sir Ian Robinson was agreed prior to his retirement and published in last year’s Remuneration Report.

(ii) The transfer value of the increases after indexation represents the current capital sum which would be required, using demographic and financial assumptions, to produce an equivalent increase in accrued pension and ancillary benefits, excluding the statutory inflationary increase, and after deduction of members’ contributions. Although the transfer value represents a liability to the pension scheme in respect of approved benefits and to the company in respect of unapproved benefits, it is not a single sum paid or due to be paid to the individual director and cannot therefore meaningfully be added to the annual remuneration. Instead, this value would not be payable until the director’s retirement date, and thereafter would be spread over the remainder of his lifetime (and also covering the cost of dependants’ benefits after his death).

(iii) With respect to Alan Richardson, the figures shown in the table above reflect the increase in his pension, including contractual changes made to enable his withdrawal. In addition, the value of allowing him to take his retirement benefits immediately was £850,750.

(iv) The pension entitlement shown is that which would be paid annually on retirement based upon service to the end of the year. Members of the group’s schemes have the option of paying additional voluntary contributions; neither the contributions nor the resulting benefits are included in the above table.

(v) Executives who joined the company on or after 1 June 1989 are subject to the earnings cap, introduced in the Finance Act 1989. Pension entitlements which cannot be provided through the company’s approved schemes due to the earnings cap are provided through unapproved pension arrangements, details of which are included in the Remuneration Report. The pension benefits disclosed above include approved and unapproved pension arrangements.

(vi) The increase in accrued pension during the year allows for an increase in inflation of RPI as measured at December 2001 (0.7%).

(vii) The value of the increase in Members’ entitlements has been calculated on the basis of actuarial advice in accordance with Actuarial Guidance note GN11, in two parts: The approved element being based upon the normal cash equivalent transfer value assumptions less directors’ contributions; the unapproved element is calculated in line with FRS 17 assumptions.

(viii) Transferred in benefits represent pension rights accrued in respect of previous employments.

(ix) The total liabilities, calculated on an FRS 17 basis, for the 14 executives and senior employees arising in relation to unapproved benefits for service for the year to 31 March 2002 was £690,000 (2001 £500,000). All benefits for the above are provided on a defined benefit basis.

Table 28—Directors’ interests in shares as at 31 March 2002

	Ordinary shares		Share options (Executive)		Share options (Sharesave)		Long Term Incentive Plan
	31.3.02	1.4.01 (or date of appointment if later)	31.3.02	1.4.01	31.3.02	1.4.01	31.3.02		1.4.01
							**Vested	*Potential	**Vested	*Potential
Charles Miller Smith	11,000	11,000	—	—	—	—	—	—	—	—
Ian Russell	•86,817	•58,418	227,743	—	4,371	—	12,682	175,063	27,691	114,694
Charles Berry	•18,958	•14,691	107,660	—	903	2,232	4,433	87,904	9,951	55,461
David Nish	•7,294	•4,112	124,223	—	2,509	2,215	4,191	85,030	–	45,286
Ken Vowles	•143,410	•138,801	124,223	—	3,073	5,501	29,796	109,308	20,768	81,655
Euan Baird	100,000	100,000	—	—	—	—	—	—	—	—
Mair Barnes	1,400	1,400	—	—	—	—	—	—	—	—
Philip Carroll	—	—	—	—	—	—	—	—	—	—
Sir Peter Gregson	1,093	1,024	—	—	—	—	—	—	—	—
Nolan Karras	31,286	27,347	—	—	—	—	—	—	—	—
Allan Leighton	—	—	—	—	—	—	—	—	—	—
EwenMacpherson	5,000	5,000	—	—	—	—	—	—	—	—

None of the directors has an interest in ordinary shares which is greater than 1% of the issued share capital of the company.

* These shares represent, in each case, the maximum number of shares which the directors may receive, dependent on the satisfaction of performance criteria as approved by shareholders in connection with the Long Term Incentive Plan.

** These shares represent the number of shares the directors are entitled to receive when the Long Term Incentive Plan award is exercisable after the fourth anniversary of grant calculated according to the performance criteria measured over the three-year performance period.

* These shares include the number of shares which the directors hold in the Employee Share Ownership Plan, shown below.

	Free shares	Partnership shares	Matching shares	Dividend shares	Total
Ian Russell	50	388	388	33	859
Charles Berry	50	388	388	33	859
David Nish	50	388	388	33	859
Ken Vowles	50	388	388	—	826

Between 31 March 2002 and 1 May 2002, Ian Russell, Charles Berry and David Nish each acquired 34 Partnership Shares and 34 Matching Shares as part of the regular monthly transactions of the Employee Share Ownership Plan. Otherwise, there have been no changes in the directors’ interests between 31 March 2002 and 1 May 2002.

52

Table 29—Directors’ interests in performance and other share plans at 31 March 2002

	1 April 2001	Granted	Exercised	Lapsed#	31 March 2002 (or date of retirement as director if earlier)	Option exercise price (pence)	Date exercised	Market price at date of exercise (pence)	Date from which exercisable	Expiry date
Long Term Incentive Plan
Ian Russell	—	—	—	—	—	nil			9 Aug 00	8 Aug 03
	27,691	—	27,691	—	—	nil	29 May 01	500.625	16 May 01	15 May 04
	31,706	—	—	19,024	12,682	nil			7 May 02	6 May 05
	37,988	—	—	—	37,988	nil			10 May 03	9 May 06
	45,000	—	—	—	45,000	nil			5 May 04	4 May 07
	—	92,075	—	—	92,075	nil			4 May 04	3 May 08
	142,385	92,075	27,691	19,024	187,745
Charles Berry	—	—	—	—	—	nil			9 Aug 00	8 Aug 03
	9,951	—	9,951	—	—	nil	31 May 01	510.25	16 May 01	15 May 04
	11,083	—	—	6,650	4,433	nil			7 May 02	6 May 05
	18,994	—	—	—	18,994	nil			10 May 03	9 May 06
	25,384	—	—	—	25,384	nil			5 May 04	4 May 07
	—	43,526	—	—	43,526	nil			4 May 04	3 May 08
	65,412	43,526	9,951	6,650	92,337
David Nish	—	—	—	—	—	nil			9 Aug 00	8 Aug 03
	—	—	—	—	—	nil			16 May 01	15 May 04
	10,479	—	—	6,288	4,191	nil			7 May 02	6 May 05
	11,731	—	—	—	11,731	nil			10 May 03	9 May 06
	23,076	—	—	—	23,076	nil			5 May 04	4 May 07
	—	50,223	—	—	50,223	nil			4 May 04	3 May 08
	45,286	50,223	—	6,288	89,221
Alan Richardson	9,661	—	9,661	—	—	nil	9 May 01	455.38	9 Aug 00	8 Aug 03
(retired 31 December 2001)	10,816	—	10,816	—	—	nil	22 May 01	473.25	16 May 01	15 May 04
	11,446	—	—	6,868	4,578	nil			7 May 02	6 May 05
	18,994	—	—	—	18,994	nil			10 May 03	9 May 06
	25,384	—	—	—	25,384	nil			5 May 04	4 May 07
	—	50,223	—	—	50,223	nil			4 May 04	3 May 08
	76,301	50,223	20,477	6,868	99,179
Sir Ian Robinson	36,072	—	—	—	36,072	nil			9 Aug 00	8 Aug 03
(retired from the Board 4 May 2001 and	40,383	—	—	—	40,383	nil			16 May 01	15 May 04
from the company on 31 May 2001)	41,916	—	—	—	41,916	nil			7 May 02	6 May 05
	46,927	—	—	—	46,927	nil			10 May 03	9 May 06
	58,53	—	—	—	58,153	nil			5 May 04	4 May 07
	223,451	—	—	—	223,451
Ken Vowles	—	—	—	—	—	nil			9 Aug 00	8 Aug 03
(retired 31 March 2002)	20,768	—	—	—	20,768	nil			16 May 01	15 May 04
	22,570	—	—	13,542	9,028	nil			7 May 02	6 May 05
	27,932	—	—	—	27,932	nil			10 May 03	9 May 06
	31,153	—	—	—	31,153	nil			5 May 04	4 May 07
	—	50,223	—	—	50,223	nil			4 May 04	3 May 08
	102,423	50,223	—	13,542	139,104

On 16 May 2001, the second awards under the Long Term Incentive Plan became exercisable. The mid-market closing price on that day was 487 pence and the value attributable to those awards at that date was £533,796. Details of awards exercised are shown in the table above.

# During the year, the performance period for awards granted under the Long Term Incentive Plan in 1998 ended and, on the basis of the company’s total shareholder return, 40% of shares under awards vested. However, awards may not be exercised until the fourth anniversary of the grant and are exercisable until the seventh anniversary.

In accordance with the rules of the Long Term Incentive Plan, retiring directors are entitled to retain a portion of Long Term Incentive Plan awards. However, following retirement, these remain subject to the performance criteria detailed in (ii) below.

As a result of the retirement of Sir Ian Robinson from the company on 31 May 2001 and in accordance with the rules of the Long Term Incentive Plan, 19,385 shares under the award of 58,153 shares granted in 2000 lapsed leaving a balance of 38,768. On 7 May 2001, 25,150 shares under the award of 41,916 shares granted in 1998 lapsed leaving a balance of 16,766 shares.

As a result of the retirement of Alan Richardson from the company on 31 December 2001 and in accordance with the rules of the Plan, 3,526 shares under the award of 25,384 shares granted in 2000 lapsed leaving a balance of 21,858 shares and 23,717 shares under the award of 50,223 shares granted in 2001 lapsed, leaving a balance of 26,506 shares.

As a result of the retirement of Ken Vowles from the company on 31 March 2002 and in accordance with the rules of the Plan, 2,791 shares under the award of 50,223 shares granted in 2001 lapsed, leaving a balance of 47,432 shares.

Footnote

Awards granted to directors under the Long Term Incentive Plan on 2 May 2002 were as follows: Ian Russell 101,600; Charles Berry 55,418; and David Nish 64,655.

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Table 29—Directors’ interests in performance and other share plans at 31 March 2002 continued

	1 April 2001	Granted	Exercised	Lapsed#	31 March 2002 (or date of retirement if earlier)	Option exercise price (pence)		Date exercised	Market price at date of exercise (pence)	Normal date from which exercisable	Normal expiry date
Executive Share Option Plan 2001
Ian Russell	—	227,743	—	—	227,743	483.0				21 Aug 04	21 Aug 11
	—	227,743	—	—	227,743
Charles Berry	—	107,660	—	—	107,660	483.0				21 Aug 04	21 Aug 11
	—	107,660	—	—	107,660
David Nish	—	124,223	—	—	124,223	483.0				21 Aug 04	21 Aug 11
	—	124,223	—	—	124,223
Alan Richardson (retired 31 December 2001)	—	124,223	—	—	124,223	483.0				21 Aug 04	21 Aug 11
	—	124,223	—	—	124,223
Ken Vowles (retired 31 March 2002)	—	124,223	—	—	124,223	483.0				21 Aug 04	21 Aug 11
	—	124,223	—	—	124,223
Sharesave Scheme
Ian Russell	—	4,371	—	—	4,371	386.0				1 Sep 06	28 Feb 07
	—	4,371	—	—	4,371
Charles Berry	1,329	—	1,329	—	—	440.0	*	3 Sep 01	489.0	1 Sep 01	28 Feb 02
	903	—	—	—	903	429.0	*			1 Sep 02	28 Feb 03
	2,232	—	1,329	—	903
David Nish	2,215	—	2,215	—	—	440.0	*	3 Sep 01	489.0	1 Sep 01	28 Feb 02
	—	2,509	—	—	2,509	386.0	*			1 Sep 04	28 Feb 05
	2,215	2,509	2,215	—	2,509
Alan Richardson (retired 31 December 2001)	1,568	—	—	—	1,568	440.0				1 Sep 03	29 Feb 04
	1,573	—	—	—	1,573	429.0				1 Sep 04	28 Feb 05
	—	874	—	—	874	386.0	*			1 Sep 06	28 Feb 07
	3,141	874	—	—	4,015
Ken Vowles (retired 31 March 2002)	3,933	—	3,933	—	–	263.1		3 Sep 01	489.0	1 Sep 01	28 Feb 02
	1,568	—	—	—	1,568	440.0				1 Sep 03	29 Feb 04
	—	1,505	—	—	1,505	386.0	*			1 Sep 04	28 Feb 05
	5,501	1,505	3,933	—	3,073

  * Denotes options granted under a three-year scheme.

(i) The market price of the shares at 28 March 2002 (the last trading day before the financial year end) was 359.50 pence and the range during 2001/02 was 350.00 pence to 521.84 pence.

(ii) The Long Term Incentive Plan makes annual awards to acquire shares in ScottishPower at nil or nominal cost to the plan participants up to a maximum value equal to 75% of base salary. The award will vest only if the Remuneration Committee is satisfied that certain performance measures related to the sustained underlying financial performance of the company and improvements in certain Ofgem published Customer Service Standards and OFWAT published levels of service are achieved over a period of three financial years commencing with the financial year preceding the date an award is made. Assuming that such targets have been achieved, the number of shares that can be acquired will be dependent upon how the company ranks in terms of its total shareholder return performance over a three-year period, in comparison to the constituent companies of the FTSE 100 index and the Electricity and Water sectors and a group of international energy companies. A percentage of each half of the award will vest depending upon the company’s ranking within each of the comparator groups. The plan participant may acquire the shares in respect of the percentage of the award which has vested at any time after the third or fourth year, as appropriate, up to the seventh year after the grant of the award. No dividends accrue to participants prior to vesting.

(iii) During the year, the Executive Share Option Plan 2001 was launched, whereby options are granted to relevant executives and senior managers. These options are subject to the performance criterion that the percentage increase in the company’s annualised earnings per share be at least 3% (adjusted for any increase in the Retail Price Index). This criterion is assessed at the end of the third financial year, the first year being the financial year starting immediately before the date of grant. If the criterion is not satisfied over this period it is tested again at the end of the fourth financial year. If the criterion is not satisfied over this period, it is tested again at the end of the fifth financial year. If the criterion is not satisfied over this period, then the options lapse. In accordance with the Plan rules, directors retiring during the year are entitled to exercise their executive options within 42 months of the date of grant (21 August 2001).

(iv) The option price for Sharesave options is calculated by reference to the middle-market quotation on the day immediately preceding the date of invitation and discounted by 20% in accordance with the Inland Revenue rules for such schemes. In accordance with the rules of the Scheme, directors retiring during the year are entitled to exercise Sharesave options within 6 months of the date of their retirement, over the number of shares which can be purchased using their savings plus interest.

(v) The number of options granted to a director under the Sharesave Scheme is calculated by reference to the total amount which the director agrees to save for a period of three or five years under an Inland Revenue approved savings contract, subject to a current maximum.

(vi) At 1 April 2001, Keith McKennon held options to acquire 145,000 ScottishPower ADSs at an option price of $32.76 exercisable from February 2003 to February 2009. One ScottishPower ADS equates to four ordinary shares, and therefore the option, expressed in ordinary shares, was over 580,000 ordinary shares. He retains these options following retirement on 27 July 2001.

(vii) Total gains made on exercise of directors’ share options and awards during the year were £295,205 (2001 £319,599).

Footnote

Options granted to directors under the Executive Share Option Plan 2001 on 2 May 2002 were as follows: Ian Russell 270,935; Charles Berry 147,783; and David Nish 172,413.

46

Directors’ responsibility for the accounts

The directors are required by law to prepare Accounts for each financial year and to present them annually to the company’s members at the Annual General Meeting. The Accounts, of which the form and content are prescribed by the Companies Act 1985 and applicable accounting standards, must give a true and fair view of the state of affairs of the company and of the group as at the end of the financial year, and of the group’s profit or loss for the period.

The directors confirm that suitable Accounting Policies have been used and applied consistently, and that reasonable and prudent judgements and estimates have been made in the preparation of the Accounts for the year ended 31 March 2002. The directors also confirm that applicable accounting standards have been followed and that the Accounts have been prepared on the going concern basis.

The directors are responsible for maintaining proper accounting records and sufficient internal controls to safeguard the assets of the company and of the group and to prevent and detect fraud or any other irregularities.

Auditors

PricewaterhouseCoopers have expressed their willingness to continue in office and a resolution to reappoint PricewaterhouseCoopers as the company’s auditors will be proposed at the Annual General Meeting.

Report of the directors

The Report of the Directors comprising the statements and reports has been approved by the Board and signed on its behalf by

By:
	Andrew Mitchell Secretary

1 May 2002

Cautionary statement for purposes of the “Safe Harbor” provisions of the Private Securities Litigation Reform Act of 1995

        Certain matters discussed in this document are “forward-looking statements” within the meaning of the US Private Securities Litigation Reform Act of 1995 (the “PSLRA”) and any rules, regulations or releases of the Securities and Exchange Commission with respect thereto. Forward-looking statements in this document include, but are not limited to, statements in: “Chief Executive’s Review” relating to PacifiCorp’s aim to achieve its target return on equity of approximately 11% by 2004/05 and achieve operating cost savings of $300 million by 2004/05, improving our cost to serve, investments in new generation, improvements in recording of the prudency of net power cost purchases and investments, the approval process for US restructuring, further investments to improve operational reliability and security of supply, participation in a Regional Transmission Organization, growth of PPM, expect PPM to be profitable in 2002/03, integration of generation assets, trading activities and energy retailing to customers, expect greater demand for gas storage services, customer service process improvements, expect cost base in 2002/03 to be at or near the UK regulatory frontier, installation of new network and upgrade of control systems; “Business Review—US Division” relating to plans to expand energy business, plans to lower cost and risk of supplying power, expectations for sources and supplies of energy requirements, prices paid by PacifiCorp to provide load balancing resources, price changes with the federal Bonneville Power Administration, forecasts for average annual growth in retail megawatt hour sales for the period from 2003 to 2006, PacifiCorp’s expectations regarding the effect of deregulation and PPM’s target of renewable development opportunities; “Business Review—UK Division” relating to maximising value of both generation and supply assets, leveraging benefits of its generation asset base and commercial trading operations, additional windfarm development; the ability of ScottishPower’s UK power stations to support generation output and timing of the upgrade of the England-Scotland transmission link and the commencement of operation of the Scotland-Northern Ireland interconnector; “Business Review—Infrastructure Division” relating to restructuring the asset-owner businesses so they now act as an integrated business unit to concentrate expertise on regulatory issues, effect on the company of the demerger of Thus Group plc and the sale of Southern Water; “Business Review—Group Employees” relating to reductions in the PacifiCorp workforce; “Business Review—Group Environmental Policy” relating to the development and effects of renewable energy sources and environmental regulations and the goal of pursuing permitting changes that tend to reduce emissions while allowing for efficient operation of thermal generating plants; “Business Review—US Business Regulation” relating to the economic impact of mandates from the Federal Power Act, the effectiveness of programs aimed at demand side management, the effects and timing of the US restructuring efforts, the effectiveness of current and future price increases, replacement agreements are expected to provide savings for residential and irrigation customers, as well as the impact of compliance costs; “Business Review—Regulation of the Electricity and Gas Industries in the UK” relating to implementation of a Great Britain-wide wholesale market for electricity and revised arrangements in respect of the interconnector between England and Scotland; “Business Review—Environmental Regulation” relating to ScottishPower’s goal of meeting or bettering environmental requirements; “Business Review—UK Environmental Regulation” relating to the effects of changes in the regulations of the UK, EU and United Nations, and the ability to comply with such regulations, ScottishPower’s expectation to meet its target of 10% generation from renewable energy sources by 2010; “Financial Review—Capital Expenditure and Cash Flow (2001/02)” relating to the description of new sources of power; “Quantitative and Qualitative Disclosures about Market Risk” relating to risk management controls and other risk management activities; “Financial Review—Financial Instruments and Risk Management” relating to the belief that the group is not exposed to any material concentration of credit risk, sensitivity analysis and impact of adverse price changes; “Financial Review—Accounting Developments” relating to the impact on future US GAAP results for upcoming financial years; and our stated dividend aim is 5% of nominal growth for each year through to March 2003.

ScottishPower wishes to caution readers, and others to whom forward-looking statements are addressed, that any such forward-looking statements are not guarantees of future performance and that actual results may differ materially from estimates in the forward-looking statements.

ScottishPower undertakes no obligation to revise these forward-looking statements to reflect events or circumstances after the date hereof. In addition to the important factors described elsewhere in this document, the following important factors, among others, could affect the group’s actual future:

— any regulatory changes (including changes in environmental regulations) that may increase the operating costs of the group, may require the group to make unforeseen capital expenditures or may prevent the regulated business of the group from achieving acceptable returns;

— future levels of industry generation and supply, demand and pricing, political stability, competition and economic growth in the relevant areas in which the group has operations;

— the availability of acceptable quality fuel at favorable prices;

— the availability of operational capacity of plants;

— the success of reorganizational and cost-saving efforts; and

— development and use of technology, the actions of competitors, natural disasters and other changes to business conditions.

55

Accounting Policies and Definitions

Definitions

Business segment definitions

ScottishPower defines business segments for management reporting purposes based on a combination of factors, principally differences in products and services and the regulatory environment in which the businesses operate.

Business segments have been included under either ‘continuing operations’ or ‘discontinued operations’ as appropriate.

The business segments of the group are defined as follows:

Continuing operations

United Kingdom

UK Division—Generation, Trading and Supply

The generation of electricity from the group’s own power stations, the purchase of external supplies of electricity and gas for sale to customers, together with related billing and collection activities, gas storage, sale of gas to industrial and domestic customers and the sale of electricity to electricity suppliers, in Scotland and England & Wales and full participation in the New Electricity Trading Arrangements (“NETA”) in England & Wales.

Infrastructure Division—Power Systems

The transmission and distribution businesses in Scotland and the distribution business of Manweb operating in Merseyside and North Wales and, specifically, the transportation of units of electricity from the power stations through the transmission and distribution networks to customers in Scotland and to customers in Northern Ireland and England & Wales through the Interconnectors.

United States

US Division—PacifiCorp

A vertically integrated electric utility that includes the generation, transmission and distribution and sale of electricity to retail, industrial and commercial customers in portions of six western states; Utah, Oregon, Wyoming, Washington, Idaho and California. The operations also include wholesale sales and power purchase transactions with various entities. The state regulatory commissions and Federal Energy Regulatory Commission (“FERC”) regulate the retail and wholesale operations. The US Division also includes businesses of other US subsidiaries not regulated as electricity utilities in the US, including PacifiCorp Power Marketing, Inc. (“PPM”) which commenced substantive operations in 2001. PPM is primarily a wind and gas development led, asset-backed marketer of power to wholesale customers in the western US. PPM also provides natural gas storage/hub services in North America.

Discontinued operations

United Kingdom

Infrastructure Division—Southern Water

The provision of water and wastewater services in the south-east of England, together with related billing and collection activities. The decision to dispose of the Southern Water business was announced on 8 March 2002 and was completed on 23 April 2002.

Thus

The provision of telecommunications services, internet access and information services to national corporates, small and medium-sized enterprises and residential customers. In 1999/00 this segment also included the operations of the mobile telephone business which was sold in November 1999 and the fixed radio access telephony operations from which the group withdrew in July 1999. Thus Group plc (“Thus”) was demerged from ScottishPower on 19 March 2002.

Appliance Retailing

The retailing and servicing of domestic electrical goods and home entertainment appliances. The business was disposed of and withdrawn from during the year ended 31 March 2002.

Revenue cost definitions

Cost of sales

The cost of sales for the group, excluding Southern Water, reflect the direct costs of the generation and purchase of electricity, the purchase of natural gas, appliance retailing and telecommunications services. For Southern Water, cost of sales represents the cost of extracting water from underground and raw water surface reservoirs and of its treatment and supply to customers and the collection of wastewater and its treatment and disposal.

    Transmission and distribution costs.

The cost of transmitting units of electricity from the power stations through the transmission and distribution networks to customers. It includes the costs of metering, billing and debt collection. This heading is considered more appropriate to the electricity industry than the standard Companies Act heading of distribution costs.

    Administrative expenses

The indirect costs of businesses, the costs of corporate services, property rates and goodwill amortisation.

Other definitions

Company or ScottishPower

Scottish Power plc.

Group

Scottish Power plc and its consolidated subsidiaries.

Associated undertakings

Entities in which the group holds a long-term participating interest and exercises significant influence.

Joint ventures

Entities in which the group holds a long-term interest and shares control with another company external to the group.

Subsidiary undertakings

Entities in which the group holds a long-term controlling interest.

56

Accounting Policies

Basis of accounting

The Accounts have been prepared under the historical cost convention, modified to include the revaluation of certain tangible fixed assets, and in accordance with applicable accounting standards in the UK and, subject to the treatment of water infrastructure grants and contributions described under ‘Grants and contributions’ below, comply with the requirements of the Companies Act 1985.

In preparing these Accounts, certain items have been included in order to comply with accounting presentation and disclosure requirements applicable in the United States in respect of foreign registrants. A reconciliation to US GAAP is set out in Note 34.

Basis of consolidation

The group Accounts include the Accounts of the company and its subsidiary undertakings together with the group’s share of results and net assets of associated undertakings and joint ventures.

For commercial reasons certain subsidiaries have a different year end. The consolidation includes the Accounts of these subsidiaries as adjusted for material transactions in the period between the year ends and 31 March.

Use of estimates

The preparation of Accounts in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Accounts and the reported amounts of revenues and expenses during the reporting period. Actual results can differ from those estimates.

Turnover

Turnover comprises the sales value of energy, goods, water, wastewater and other services supplied to customers during the year and excludes Value Added Tax and intra-group sales. Income from the sale of energy and measured water is the value of units supplied during the year and includes an estimate of the value of units supplied to customers between the date of their last meter reading and the year end.

Interest

Interest on the funding attributable to capital projects is capitalised gross of tax relief during the period of construction and written off as part of the total cost over the operational life of the asset. All other interest payable and receivable is reflected in the profit and loss account as it arises.

Financial instruments

Debt instruments

All borrowings are stated at the fair value of consideration received after deduction of issue costs. The issue costs and interest payable on bonds are charged to the profit and loss account at a constant rate over the life of the bond. Premiums and discounts arising on the early repayment of borrowings are recognised in the profit and loss account as incurred.

Interest rate swaps/Forward rate agreements

These are used to manage debt interest rate exposures. Amounts payable or receivable in respect of these agreements are recognised as adjustments to interest expense over the period of the contracts. The cash flows from, and gains and losses arising on terminations of, these contracts are recognised as returns on investments and servicing of finance. Where associated debt is not retired in conjunction with the termination of an interest swap, gains and losses are deferred and are amortised to interest expense over the remaining life of the associated debt to the extent that such debt remains outstanding.

Interest rate caps/Swaptions/Options

Premiums received and payable on these contracts are amortised over the period of the contracts and are disclosed as interest income and expense. The accounting for interest rate caps and swaptions is otherwise in accordance with interest rate swaps detailed above.

Cross currency interest rate swaps

        These are used both to hedge foreign exchange and interest rate exposures arising on foreign currency debt and to hedge overseas net investment. Where used to hedge debt issues, the debt is recorded at the hedge contracted rate and accounting is otherwise in accordance with interest rate swaps detailed above. Where used to hedge overseas net investment, spot gains or losses are recorded in the statement of total recognised gains and losses, with interest recorded in the profit and loss account.

Forward contracts

        The group enters into forward contracts for the purchase and/or sale of foreign currencies in order to manage its exposure to fluctuations in currency rates and to hedge overseas net investment. Unrealised gains and losses on contracts are not accounted for until the maturity of the contract. The cash flows from forward purchase contracts are classified in a manner consistent with the underlying nature of the hedged transaction. Hence, spot gains or losses on hedges of the overseas net investment are recorded in the statement of total recognised gains and losses with the interest rate differential reflected in the profit and loss account. In addition, foreign currency debtors and creditors that are hedged with forward contracts are translated at the contracted rate at the balance sheet date. Where a currency forward contract no longer represents a hedge because either the underlying asset or liability has been derecognised, or the effectiveness of the hedge has been undermined, it is restated at fair value and any change in value is taken directly to the profit and loss account and reported within exchange losses.

Hydro-electric and temperature hedges

These instruments are used to hedge fluctuations in weather and temperature in the US. On a periodic basis, the group estimates and records a gain or loss in the profit and loss account corresponding to the total expected future cash flows from these contracts.

Commodity contracts

Where there is no physical delivery associated with commodity contracts, they are recorded at fair value on the balance sheet and movements reflected through the profit and loss account. Gas future contracts are undertaken for hedging and proprietary trading purposes. Where the instrument is a hedge, the daily margin calls are initially reflected on the balance sheet and subsequently reflected through

57

the profit and loss account to match the recognition of the hedged item. Where the instrument is for proprietary trading the margin calls are reflected through the profit and loss account.

Taxation

In accordance with Financial Reporting Standard 19 ‘Deferred tax’, full provision is made for deferred tax on a non-discounted basis.

Goodwill

Purchased goodwill represents the excess of the fair value of the purchase consideration over the fair value of the net assets acquired. Goodwill arising from the purchase of trading entities in accounting periods prior to 31 March 1998 was written off on acquisition against reserves. On disposal of trading entities, the goodwill previously included in reserves is charged to the profit and loss account matched by an equal credit to reserves. Goodwill arising on acquisitions since 1 April 1998 has been capitalised and amortised through the profit and loss account over its estimated useful economic life. Goodwill arising on overseas acquisitions is regarded as a currency asset and is retranslated at the end of each period at the closing rate of exchange.

Tangible fixed assets

Accounting for non-water infrastructure assets

Tangible fixed assets are stated at cost or valuation and are generally depreciated on the straight line method over their estimated operational lives. Tangible fixed assets include capitalised employee, interest and other costs which are directly attributable to construction of fixed assets.

Land is not depreciated except in the case of mines (see below). The main depreciation periods used by the group are as set out below.

	Years
Coal, oil-fired, gas and other generating stations	22-45
Hydro plant and machinery	20-100
Other buildings	40
Transmission and distribution plant	20-75
Towers, lines and underground cables	40-60
Vehicles, computer software costs, miscellaneous equipment and fittings	3-40

The carrying values of tangible fixed assets are reviewed for impairment in periods if events or changes in circumstances indicate the carrying value may not be recoverable. For those assets with estimated remaining useful economic lives of more than 50 years, impairment reviews are undertaken annually. Impairment losses are recognised in the period in which they are identified.

Mine reclamation and closure costs

Provision is made for mine reclamation and closure costs when an obligation arises out of events prior to the year end. The amount recognised is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. A corresponding tangible fixed asset is also created of an amount equal to the provision. This asset, together with the cost of the mine, is subsequently depreciated on a unit of production basis. The unwinding of the discount is included within net interest and similar charges.

Decommissioning costs

Provision is made for the estimated decommissioning costs at the end of the producing lives of the group’s power stations on a discounted basis. Capitalised decommissioning costs are depreciated over the useful lives of the related assets. The unwinding of the discount is included within net interest and similar charges.

Infrastructure accounting

Water infrastructure assets, being mains and sewers, reservoirs, dams, sludge pipelines and sea outfalls comprise a network of systems. Expenditure on water infrastructure assets relating to increases in capacity or enhancement of the network and on maintaining the operating capability of the network in accordance with defined standards of service is treated as an addition to fixed assets.

        The depreciation charge for water infrastructure assets is the estimated level of annualised expenditure required to maintain the operating capability of the network and is based on the asset management plan agreed with the water industry regulator as part of the price regulation process.

The asset management plan is developed from historical experience combined with a rolling programme of reviews of the condition of the infrastructure assets.

Leased assets

As lessee

Assets leased under finance leases are capitalised and depreciated over the shorter of the lease periods and the estimated operational lives of the assets. The interest element of the finance lease repayments is charged to the profit and loss account in proportion to the balance of the capital repayments outstanding. Rentals payable under operating leases are charged to the profit and loss account on a straight line basis.

As lessor

Rentals receivable under finance leases are allocated to accounting periods to give a constant periodic rate of return on the net cash investment in the lease in each period. The amounts due from lessees under finance leases are recorded in the balance sheet as a debtor at the amount of the net investment in the lease after making provisions for bad and doubtful rentals receivable.

Investments

Investments in subsidiary and associated undertakings and joint ventures are stated in the balance sheet of the parent company at cost, or nominal value of shares issued as consideration where applicable, less provision for any impairment in value. The group profit and loss account includes the group’s share of the operating profits less losses, net interest charge and taxation of associated undertakings and joint ventures. The group balance sheet includes the investment in associated undertakings and joint ventures at the group’s share of their net assets. Other fixed asset investments are carried at cost less provision for impairment in value.

Own shares held under trust

The amount recorded in the balance sheet for shares in the company purchased for employee sharesave schemes represents the amounts receivable from option holders on exercise of the options.

The group has taken advantage of the exemption within Urgent Issues Task Force (“UITF”) Abstract 17 not to apply the requirements therein to Inland Revenue approved savings-related share option schemes and equivalent overseas schemes.

58

Long Term Incentive Plan (“LTIP”)

Shares in the company purchased for the LTIP are held under trust and are recorded within investments in the balance sheet at cost. The cost of awards made by the trust under the LTIP, being the difference between the fair value of the shares and the option price at the date of grant, is taken to the profit and loss account on a straight line basis over the period in which performance is measured.

Stocks

Stocks are valued at the lower of average cost and net realisable value.

US regulatory assets

Statement of Financial Accounting Standard (“FAS”) 71 ‘Accounting for the Effects of Certain Types of Regulation’ establishes US GAAP for utilities in the US whose regulators have the power to approve and/or regulate rates that may be charged to customers. Provided that, through the regulatory process, the utility is substantially assured of recovering its allowable costs by the collection of revenue from its customers, such costs not yet recovered are deferred as regulatory assets. Due to the different regulatory environment, no equivalent GAAP applies in the UK.

Under UK GAAP, the group’s policy is to recognise regulatory assets established in accordance with FAS 71 only where they comprise rights or other access to future economic benefits which have arisen as a result of past transactions or events which have created an obligation to transfer economic benefits to a third party.

Measurement of the past transaction or event and hence the regulatory asset, is determined in accordance with UK GAAP.

Grants and contributions

Capital grants and customer contributions in respect of additions to non-water infrastructure fixed assets are treated as deferred income and released to the profit and loss account over the estimated operational lives of the related assets. Grants and contributions receivable relating to water infrastructure assets are deducted from the cost or valuation of those assets. While this treatment is in accordance with SSAP 4, it is not in accordance with the Companies Act 1985.

The Act requires capital grants and contributions to be shown as deferred income rather than offset against the cost or valuation of tangible fixed assets.

This departure from the requirements of the Act is, in the opinion of the directors, necessary for the Accounts to give a true and fair view as, while provision is made for depreciation of water infrastructure assets, these assets do not have determinable finite lives and therefore no basis exists on which to recognise grants and contributions as deferred income. The effect of this treatment on the value of tangible fixed assets is disclosed in Note 17.

Pensions

The group provides pension benefits through both defined benefit and defined contribution arrangements. The regular cost of providing pensions and related benefits and any variations from regular cost arising from the actuarial valuations for defined benefit schemes are charged to the profit and loss account over the expected remaining service lives of current employees following consultations with the actuary. Any difference between the charge to the profit and loss account and the actual contributions paid to the pension schemes is included as an asset or liability in the balance sheet. Payments to defined contribution schemes are charged against profits as incurred.

Post-retirement benefits other than pensions

Certain additional post-retirement benefits, principally healthcare benefits, are provided to eligible retirees within the group’s US businesses. The estimated cost of providing such benefits is charged against profits on a systematic basis over the employees’ working lives within the group.

Environmental liabilities

Provision for environmental liabilities is made when expenditure on remedial work is probable and the group is obliged, either legally or constructively through its environmental policies, to undertake such work. Where the amount is expected to be incurred over the long-term, the amount recognised is the present value of the estimated future expenditure and the unwinding of the discount is included within net interest and similar charges.

Foreign currencies

    Group

The results and cash flows of overseas subsidiaries are translated to sterling at the average rate of exchange for each quarter of the financial year. The net assets of such subsidiaries and the goodwill arising on their acquisition are translated to sterling at the closing rates of exchange ruling at the balance sheet date. Exchange differences which relate to the translation of overseas subsidiaries and of matching foreign currency borrowings are taken directly to group reserves and are shown in the statement of total recognised gains and losses.

    Company

Transactions in foreign currencies are recorded at the rate ruling at the date of the transaction. At the year end, monetary assets and liabilities denominated in foreign currencies are translated at the rate of exchange ruling at the balance sheet date or, where applicable, at the contracted rate. Any gain or loss arising on the restatement of such balances is taken to the profit and loss account.

Overseas net investments that are partially hedged with foreign currency borrowings are viewed as a foreign currency asset to the extent that they are matched with foreign currency borrowings. Exchange differences arising on re-translation of the investment and the borrowings are taken directly to reserves. The remaining unhedged element of the investment is recorded at historical cost at the exchange rate ruling at the date of acquisition without further re-translation.

59

ACCOUNTING POLICIES AND DEFINITIONS

Exchange rates

The exchange rates applied in the preparation of the Accounts were as follows:

	Year ended 31 March
	2002			2001			2000
Average rate for quarters ending:
30 June	$	1.42/	£	$	1.53/	£		—
30 September	$	1.44/	£	$	1.48/	£		—
31 December	$	1.44/	£	$	1.45/	£	$	1.62/	£
31 March	$	1.43/	£	$	1.46/	£	$	1.61/	£
Closing rate as at 31 March	$	1.42/	£	$	1.42/	£	$	1.60/	£

A glossary of terms used in the Accounts and their US equivalents is set out on page 113.

60

GROUP PROFIT AND LOSS ACCOUNT

For the year ended 31 March 2002

		Year ended 31 March 2002
	Notes	Continuing operations 2002 £m		Exceptional item —continuing operations (Note 4) 2002 £m		Total continuing operations 2002 £m		Discontinued operations 2002 £m		Exceptional items —discontinued operations (Note 4) 2002 £m		Total discontinued operations 2002 £m		Total 2002 £m
Turnover: group and share of joint ventures and associates		5,545.9		—		5,545.9		791.3		—		791.3		6,337.2
Less: share of turnover in joint ventures		(22.6	)	—		(22.6	)	—		—		—		(22.6	)
Less: share of turnover in associates		(0.5	)	—		(0.5	)	—		—		—		(0.5	)
Group turnover	1	5,522.8		—		5,522.8		791.3		—		791.3		6,314.1
Cost of sales		(3,920.0	)	—		(3,920.0	)	(490.8	)	—		(490.8	)	(4,410.8	)
Gross profit		1,602.8		—		1,602.8		300.5		—		300.5		1,903.3
Transmission and distribution costs		(479.3	)	—		(479.3	)	(33.3	)	—		(33.3	)	(512.6	)
Administrative expenses (including goodwill amortisation)		(533.8	)	(18.5	)	(552.3	)	(142.8	)	—		(142.8	)	(695.1	)
Other operating income		64.2		—		64.2		3.6		—		3.6		67.8
Utilisation of Appliance Retailing disposal provision		—		—		—		13.2		—		13.2		13.2
Operating profit before goodwill amortisation		800.5		(18.5	)	782.0		143.6		—		143.6		925.6
Goodwill amortisation		(146.6	)	—		(146.6	)	(2.4	)	—		(2.4	)	(149.0	)
Operating profit	1,2	653.9		(18.5	)	635.4		141.2		—		141.2		776.6
Share of operating profit in joint ventures		2.2		—		2.2		—		—		—		2.2
Share of operating profit in associates		0.2		—		0.2		—		—		—		0.2
		656.3		(18.5	)	637.8		141.2		—		141.2		779.0
Loss on disposal of and withdrawal from Appliance Retailing before goodwill write back		—		—		—		—		(105.0	)	(105.0	)	(105.0	)
Goodwill write back		—		—		—		—		(15.1	)	(15.1	)	(15.1	)
Loss on disposal of and withdrawal from Appliance Retailing		—		—		—		—		(120.1	)	(120.1	)	(120.1	)
Provision for loss on disposal of Southern Water before goodwill write back		—		—		—		—		(449.3	)	(449.3	)	(449.3	)
Goodwill write back		—		—		—		—		(738.2	)	(738.2	)	(738.2	)
Provision for loss on disposal of Southern Water		—		—		—		—		(1,187.5	)	(1,187.5	)	(1,187.5	)
Profit/(loss) on ordinary activities before interest		656.3		(18.5	)	637.8		141.2		(1,307.6	)	(1,166.4	)	(528.6	)
Net interest and similar charges
—Group before exceptional interest and similar charges														(373.2	)
—Exceptional interest and similar charges	4													(30.8	)
—Joint ventures														(6.2	)
	5													(410.2	)
Loss on ordinary activities before goodwill amortisation and taxation														(789.8	)
Goodwill amortisation														(149.0	)
Loss on ordinary activities before taxation														(938.8	)
Taxation
—Group before tax on exceptional items														(123.1	)
—Tax on exceptional items	4													38.8
—Joint ventures														1.1
	6													(83.2	)
Loss after taxation														(1,022.0	)
Minority interests	28													34.9
Loss for the financial year														(987.1	)
Dividends
—Cash	8													(503.5	)
—Dividend in specie on demerger of Thus	8													(436.6	)
														(940.1	)
Loss retained	27													(1,927.2	)
Loss per ordinary share	7													(53.71	)p
Adjusting items—exceptional items														71.72p
—goodwill amortisation														8.11p
Earnings per ordinary share before exceptional items and goodwill amortisation	7													26.12p
Diluted loss per ordinary share	7													(53.64	)p
Adjusting items—exceptional items														71.63p
—goodwill amortisation														8.10p
Diluted earnings per ordinary share before exceptional items and goodwill amortisation	7													26.09p
Cash dividends per ordinary share	8													27.34p

The Accounting Policies and Definitions on pages 56 to 60, together with the Notes on pages 65 to 70, 72 to 74, 76 to 107 and 109 to 110 form part of these Accounts.

61

GROUP PROFIT AND LOSS ACCOUNT

for the year ended 31 March 2001

		Year ended 31 March 2001
	Notes	Continuing operations 2001 £m		Exceptional item—   continuing operations (Note 4) 2001 £m		Total continuing operations 2001 £m		Total discontinued operations 2001 £m		Total 2001 £m
Turnover: group and share of joint ventures and associates		5,421.9		—		5,421.9		939.5		6,361.4
Less: share of turnover in joint ventures		(11.7	)	—		(11.7	)	—		(11.7	)
Less: share of turnover in associates		(0.4	)	—		(0.4	)	—		(0.4	)
Group turnover	1	5,409.8		—		5,409.8		939.5		6,349.3
Cost of sales		(3,837.0	)	(62.1	)	(3,899.1	)	(570.4	)	(4,469.5	)
Gross profit		1,572.8		(62.1	)	1,510.7		369.1		1,879.8
Transmission and distribution costs		(483.2	)	(45.1	)	(528.3	)	(38.4	)	(566.7	)
Administrative expenses (including goodwill amortisation)		(446.1	)	(13.5	)	(459.6	)	(182.0	)	(641.6	)
Other operating income		46.6		—		46.6		3.8		50.4
Operating profit before goodwill amortisation		815.3		(120.7	)	694.6		154.9		849.5
Goodwill amortisation		(125.2	)	—		(125.2	)	(2.4	)	(127.6	)
Operating profit	1,2	690.1		(120.7	)	569.4		152.5		721.9
Share of operating loss in joint ventures		(9.4	)	—		(9.4	)	—		(9.4	)
Share of operating profit in associates		0.1		—		0.1		—		0.1
Profit on ordinary activities before interest		680.8		(120.7	)	560.1		152.5		712.6
Net interest and similar charges
—Group										(330.0	)
—Joint ventures										(2.9	)
	5									(332.9	)
Profit on ordinary activities before goodwill amortisation and taxation										507.3
Goodwill amortisation										(127.6	)
Profit on ordinary activities before taxation										379.7
Taxation
—Group before tax on exceptional item										(139.2	)
—Tax on exceptional item	4									45.9
—Joint ventures										(1.9	)
	6									(95.2	)
Profit after taxation										284.5
Minority interests	28									23.0
Profit for the financial year										307.5
Dividends	8									(477.3	)
Loss retained	27									(169.8	)
Earnings per ordinary share	7									16.80p
Adjusting items—exceptional item										4.09p
—goodwill amortisation										6.97p
Earnings per ordinary share before exceptional item and goodwill amortisation	7									27.86p
Diluted earnings per ordinary share	7									16.74p
Adjusting items—exceptional item										4.07p
—goodwill amortisation										6.94p
Diluted earnings per ordinary share before exceptional item and goodwill amortisation	7									27.75p
Cash dividends per ordinary share	8									26.04p

The Accounting Policies and Definitions on pages 56 to 60, together with the Notes on pages 65 to 70, 72 to 74, 76 to 107 and 109 to 110 form part of these Accounts.

62

GROUP PROFIT AND LOSS ACCOUNT

for the year ended 31 March 2000

		Year ended 31 March 2000
	Notes	Continuing operations 2000 £m		Exceptional items—   continuing operations (Note 4) 2000 £m		Total continuing operations 2000 £m		Discontinued operations 2000 £m		Exceptional items—  discontinued operations (Note 4) 2000 £m		Total discontinued operations 2000 £m		Total 2000 £m
Turnover: group and share of joint ventures and associates		3,117.9		—		3,117.9		1,005.2		—		1,005.2		4,123.1
Less: share of turnover in joint ventures		(7.6	)	—		(7.6	)	—		—		—		(7.6	)
Less: share of turnover in associates		(0.5	)	—		(0.5	)	—		—		—		(0.5	)
Group turnover	1	3,109.8		—		3,109.8		1,005.2		—		1,005.2		4,115.0
Cost of sales		(1,891.4	)	(173.5	)	(2,064.9	)	(533.3	)	—		(533.3	)	(2,598.2	)
Gross profit		1,218.4		(173.5	)	1,044.9		471.9		—		471.9		1,516.8
Transmission and distribution costs		(314.3	)	(61.1	)	(375.4	)	(36.6	)	—		(36.6	)	(412.0	)
Administrative expenses (including goodwill amortisation)		(300.9	)	(9.8	)	(310.7	)	(157.8	)	(14.6	)	(172.4	)	(483.1	)
Other operating income		36.4		—		36.4		3.9		—		3.9		40.3
Operating profit before goodwill amortisation		676.4		(244.4	)	432.0		285.0		(14.6	)	270.4		702.4
Goodwill amortisation		(36.8	)	—		(36.8	)	(3.6	)	—		(3.6	)	(40.4	)
Operating profit	1,2	639.6		(244.4	)	395.2		281.4		(14.6	)	266.8		662.0
Share of operating profit/(loss) in joint ventures		1.6		(3.3	)	(1.7	)	—		—		—		(1.7	)
Share of operating profit in associates		0.1		—		0.1		—		—		—		0.1
		641.3		(247.7	)	393.6		281.4		(14.6	)	266.8		660.4
Gain on partial disposal of Thus		—		—		—		—		787.0		787.0		787.0
Loss on disposal of and withdrawal from other Telecoms operations		—		—		—		—		(55.0	)	(55.0	)	(55.0	)
Profit on ordinary activities before interest		641.3		(247.7	)	393.6		281.4		717.4		998.8		1,392.4
Net interest and similar charges
—Group before exceptional interest and similar charges														(226.1	)
—Exceptional interest and similar charges	4													(15.9	)
—Joint ventures														(1.4	)
	5													(243.4	)
Profit on ordinary activities before goodwill amortisation and taxation														1,189.4
Goodwill amortisation														(40.4	)
Profit on ordinary activities before taxation														1,149.0
Taxation
—Group before tax on exceptional items														(207.0	)
—Tax on exceptional items	4													(56.0	)
—Joint ventures														0.1
	6													(262.9	)
Profit after taxation														886.1
Minority interests														(1.1	)
Profit for the financial year														885.0
Dividends	8													(341.4	)
Profit retained	27													543.6
Earnings per ordinary share	7													63.69p
Adjusting items—exceptional items														(28.63	)p
—goodwill amortisation														2.91p
Earnings per ordinary share before exceptional items and goodwill amortisation	7													37.97p
Diluted earnings per ordinary share	7													63.25p
Adjusting items—exceptional items														(28.43	)p
—goodwill amortisation														2.89p
Diluted earnings per ordinary share before exceptional items and goodwill amortisation	7													37.71p
Cash dividends per ordinary share	8													24.80p

        The Accounting Policies and Definitions on pages 56 to 60, together with the Notes on pages 65 to 70, 72 to 74, 76 to 107 and 109 to 110 form part of these Accounts.

63

STATEMENT OF TOTAL RECOGNISED GAINS AND LOSSES

for the year ended 31 March 2002

	Note	2002 £m		2001 £m	2000 £m
(Loss)/profit for the financial year		(987.1	)	307.5	885.0
Exchange movement on translation of overseas results and net assets	27	(4.2	)	493.1	24.9
Currency translation differences on foreign currency hedging	27	(19.5	)	—	—
Unrealised gains on fixed asset disposals	27	4.9		—	—
Total recognised gains and losses for the financial year		(1,005.9	)	800.6	909.9

NOTE OF HISTORICAL COST PROFITS AND LOSSES

for the year ended 31 March 2002

	Note	2002 £m		2001 £m		2000 £m
(Loss)/profit on ordinary activities before taxation		(938.8	)	379.7		1,149.0
Differences between historical cost depreciation charge and actual depreciation charge for the year calculated on the revalued amount of fixed assets	27	3.4		3.4		3.4
Fixed asset revaluation gains realised on disposal	27	168.2		—		—
Historical cost (loss)/profit on ordinary activities before taxation		(767.2	)	383.1		1,152.4
Historical cost (loss)/profit retained for the financial year after taxation, minority interest and dividends		(1,755.6	)	(166.4	)	547.0

RECONCILIATION OF MOVEMENTS IN SHAREHOLDERS’ FUNDS

for the year ended 31 March 2002

	2002 £m		2001 £m		2000 £m
(Loss)/profit for the financial year	(987.1	)	307.5		885.0
Dividends (including dividend in specie)	(940.1	)	(477.3	)	(341.4	)
(Loss)/profit retained	(1,927.2	)	(169.8	)	543.6
Exchange movement on translation of overseas results and net assets	(4.2	)	493.1		24.9
Currency translation differences on foreign currency hedging	(19.5	)	—		—
Unrealised gains on fixed asset disposals	4.9		—		—
Share capital issued	16.2		6.6		4,071.2
Share buy-back (including costs)	—		—		(302.0	)
Impairment of goodwill previously written off to reserves	—		—		7.5
Goodwill realised on disposals	753.3		—		15.3
Goodwill realised on demerger of Thus	14.7		—		—
Net movement in shareholders’ funds	(1,161.8	)	329.9		4,360.5
Opening shareholders’ funds	5,893.2		5,563.3		1,202.8
Closing shareholders’ funds	4,731.4		5,893.2		5,563.3

The Accounting Policies and Definitions on pages 56 to 60, together with the Notes on pages 65 to 70, 72 to 74, 76 to 107 and 109 to 110 form part of these Accounts.

64

NOTES TO THE GROUP PROFIT AND LOSS ACCOUNT

for the year ended 31 March 2002

1    Segmental information

(a)  Turnover by segment

	Notes	Total turnover			Inter-segment turnover			External turnover
		2002 £m	2001 £m	2000 £m	2002 £m	2001 £m	2000 £m	2002 £m	2001 £m	2000 £m
United Kingdom
UK Division—Generation, Trading and Supply	(i)	2,160.7	2,099.1	2,199.2	39.3	35.3	11.3	2,121.4	2,063.8	2,187.9
Infrastructure Division—Power Systems	(i)	646.6	666.3	781.6	399.0	442.6	571.4	247.6	223.7	210.2
United Kingdom total—continuing operations								2,369.0	2,287.5	2,398.1
United States—continuing operations
US Division—PacifiCorp	(ii)	3,153.8	3,122.3	711.7	—	—	—	3,153.8	3,122.3	711.7
Total continuing operations								5,522.8	5,409.8	3,109.8
United Kingdom—discontinued operations
Infrastructure Division—Southern Water	(i)	430.6	422.9	474.1	0.7	0.5	0.9	429.9	422.4	473.2
Thus	(iii)	257.8	233.8	243.2	28.7	34.4	40.4	229.1	199.4	202.8
Appliance Retailing	(i)	133.9	325.4	336.2	1.6	7.7	7.0	132.3	317.7	329.2
United Kingdom total—discontinued operations								791.3	939.5	1,005.2
Total	(iv)							6,314.1	6,349.3	4,115.0

(b)  Operating profit/(loss) by segment

	Notes		Before goodwill amortisation and exceptional item 2002 £m		Goodwill amortisation 2002 £m		Exceptional item 2002 £m		2002 £m		Before goodwill amortisation and exceptional item 2001 £m		Goodwill amortisation 2001 £m		Exceptional item 2001 £m		2001 £m		Before goodwill amortisation and exceptional items 2000 £m		Goodwill amortisation 2000 £m		Exceptional items 2000 £m		2000 £m
United Kingdom
UK Division—Generation, Trading and Supply	(i	)	78.7		(4.9	)	(18.5	)	55.3		122.7		(0.4	)	—		122.3		156.3		—		(185.5	)	(29.2	)
Infrastructure Division—Power Systems	(i	)	354.9		—		—		354.9		341.3		—		—		341.3		368.4		—		(58.9	)	309.5
United Kingdom total—continuing operations			433.6		(4.9	)	(18.5	)	410.2		464.0		(0.4	)	—		463.6		524.7		—		(244.4	)	280.3
United States—continuing operations
US Division—PacifiCorp			366.9		(141.7	)	—		225.2		351.3		(124.8	)	(120.7	)	105.8		151.7		(36.8	)	—		114.9
Total continuing operations			800.5		(146.6	)	(18.5	)	635.4		815.3		(125.2	)	(120.7	)	569.4		676.4		(36.8	)	(244.4	)	395.2
United Kingdom—discontinued operations
Infrastructure Division—Southern Water	(i	)	216.3		—		—		216.3		221.6		—		—		221.6		287.4		—		(8.4	)	279.0
Thus	(iii	)	(63.7	)	(2.4	)	—		(66.1	)	(58.0	)	(2.4	)	—		(60.4	)	(9.5	)	(3.6	)	—		(13.1	)
Appliance Retailing	(i	)	(9.0	)	—		—		(9.0	)	(8.7	)	—		—		(8.7	)	7.1		—		(6.2	)	0.9
United Kingdom total—discontinued operations			143.6		(2.4	)	—		141.2		154.9		(2.4	)	—		152.5		285.0		(3.6	)	(14.6	)	266.8
Total			944.1		(149.0	)	(18.5	)	776.6		970.2		(127.6	)	(120.7	)	721.9		961.4		(40.4	)	(259.0	)	662.0

(c)  Depreciation and impairment by segment

	Notes	Depreciation 2002 £m	Impairment 2002 £m	Total 2002 £m	Depreciation 2001 £m	Depreciation 2000 £m	Impairment 2000 £m	Total 2000 £m
United Kingdom
UK Division— Generation, Trading and Supply	(i)	72.9	13.0	85.9	51.6	29.3	66.4	95.7
Infrastructure Division—Power Systems	(i)	108.3	—	108.3	107.6	114.5	25.6	140.1
United Kingdom total—continuing operations		181.2	13.0	194.2	159.2	143.8	92.0	235.8
United States—continuing operations
US Division—PacifiCorp		227.8	—	227.8	203.6	76.6	—	76.6
Total continuing operations		409.0	13.0	422.0	362.8	220.4	92.0	312.4
United Kingdom—discontinued operations
Infrastructure Division—Southern Water	(i)	77.6	—	77.6	71.2	67.8	—	67.8
Thus	(iii)	65.2	—	65.2	36.5	23.5	—	23.5
Appliance Retailing	(i)	3.2	—	3.2	9.8	8.5	4.9	13.4
United Kingdom total—discontinued operations		146.0	—	146.0	117.5	99.8	4.9	104.7
Total depreciation and impairment charged to operating profit		555.0	13.0	568.0	480.3	320.2	96.9	417.1
Impairment within loss on disposal of and withdrawal from other Telecoms operations		—	—	—	—	—	38.5	38.5
Impairment within loss on disposal of and withdrawal from Appliance Retailing		—	32.2	32.2	—	—	—	—
Impairment within provision for loss on disposal of Southern Water		—	449.3	449.3	—	—	—	—
Total depreciation and impairment		555.0	494.5	1,049.5	480.3	320.2	135.4	455.6

65

NOTES TO THE GROUP PROFIT AND LOSS ACCOUNT

for the year ended 31 March 2002—continued

(i) As announced in May 2001, the group operates through three divisions which are different from the segments presented in the prior year’s Accounts. The former Generation Wholesale and Energy Supply segments have been combined and the former Other segment (other than Appliance Retailing) has been absorbed into the new UK business segments. Prior year comparatives have been restated accordingly. The previously reported external turnover, operating profit, exceptional items, depreciation and impairment of the Other segment have been allocated as follows:

	Year ended 31 March 2001				Year ended 31 March 2000
	External turnover £m	Operating profit £m		Depreciation £m	External turnover £m	Operating profit £m		Exceptional items £m		Depreciation £m	Impairment £m
United Kingdom
UK Division—Generation, Trading and Supply	79.9	(6.3	)	7.6	30.8	(1.1	)	(3.8	)	4.6	—
Infrastructure Division
Power Systems	11.1	17.1		6.5	37.6	7.2		(1.2	)	6.3	—
Southern Water	0.8	0.4		—	2.7	0.9		—		1.7	—
Appliance Retailing	317.7	(8.7	)	9.8	329.2	7.1		(6.2	)	8.5	4.9
Other total	409.5	2.5		23.9	400.3	14.1		(11.2	)	21.1	4.9

(ii) Turnover for PacifiCorp for the year ended 31 March 2000 amounted to £2,499.6 million.

(iii) The segment previously described as ‘Telecoms’ has been redesignated ‘Thus’ as historical data for this segment no longer includes data relating to other Telecoms operations disposed in prior years except that, in the year ended 31 March 2000, this segment included external turnover of £25.7 million in respect of the group’s mobile telephone business which was disposed of in November 1999.

(iv) In the segmental analysis turnover is shown by geographical origin. Turnover analysed by geographical destination is not materially different.

(v) As required by the Utilities Act 2000, the group has implemented a new legal entity structure for certain of its UK businesses to give effect to business separation. Following the creation of this new legal structure on 1 October 2001, the directors reviewed the group’s segments and concluded that no changes were required to the business segments disclosed above.

2    Operating profit

	2002 £m		2001 £m		2000 £m
Operating profit is stated after charging/(crediting):
Depreciation and impairment of tangible fixed assets	568.0		480.3		417.1
Amortisation of goodwill	149.0		127.6		40.4
Release of customer contributions/grants	(17.8	)	(15.1	)	(15.6	)
Research and development	3.1		4.2		5.5
Hire of plant and equipment—operating leases	0.1		0.3		0.4
Hire of other assets—operating leases	55.6		54.6		44.7
Auditors’ remuneration for audit of
—group	1.5		1.5		1.1
—company	—		—		—
Non-audit fees paid to auditors:
Regulatory advice	0.3		1.3		1.2
Advice on systems and consultancy services	6.9		5.4		3.9
Taxation, compliance and advice	5.2		3.1		1.2
Due diligence, UK Listing Authority and SEC reporting	3.4		0.8		3.7
Other audit and assurances services	0.8		0.8		0.1
Total UK and US non-audit fees paid to auditors	16.6		11.4		10.1

For the year ended 31 March 2002, £15.1 million of the above non-audit fees were charged to operating profit, £0.6 million were charged to exceptional loss on disposal of and withdrawal from Appliance Retailing and £0.9 million were charged to exceptional provision for loss on disposal of Southern Water.

For the year ended 31 March 2001, £10.7 million of the above non-audit fees were charged to operating profit and £0.7 million were included within the costs of sale of the businesses held for disposal.

For the year ended 31 March 2000, £6.6 million of the above non-audit fees were charged to operating profit, £3.1 million were charged to exceptional gain on the partial disposal of Thus and £0.4 million were included within costs of acquisition of PacifiCorp.

        Operating profit for the years ended 31 March 2002, 31 March 2001 and 31 March 2000 is also stated after crediting net earnings of £4.2 million, £4.3 million and £1.3 million respectively under finance leases in the United States, which are financed by non-recourse borrowings and qualify for linked presentation under FRS 5. Net earnings comprise gross earnings of £32.3 million, £33.8 million and £10.8 million less finance costs of £28.1 million, £29.5 million and £9.5 million respectively.

66

3    Employee information

(a)  Employee costs

	2002 £m		2001 £m		2000 £m
Wages and salaries	695.6		676.8		464.7
Social security costs	46.9		50.3		33.7
Pension costs	34.8		28.4		20.9
Total employee costs	777.3		755.5		519.3
Less: charged as capital expenditure	(191.3	)	(151.2	)	(89.4	)
Charged to the profit and loss account	586.0		604.3		429.9

(b)  Employee numbers

The year end and average numbers of employees (full-time and part-time) employed by the group, including executive directors, were:

			At 31 March			Annual average
	Notes		2002	2001	2000	2002	2001	2000
United Kingdom
UK Division—Generation, Trading and Supply	(i	)	4,582	4,278	3,221	4,589	4,178	3,298
Infrastructure Division—Power Systems	(i	)	3,084	3,265	5,564	3,174	3,332	5,591
United Kingdom total—continuing operations			7,666	7,543	8,785	7,763	7,510	8,889
United States—continuing operations
US Division—PacifiCorp			6,387	6,668	7,789	6,512	7,053	7,914
Total continuing operations			14,053	14,211	16,574	14,275	14,563	16,803
United Kingdom—discontinued operations
Infrastructure Division—Southern Water	(i	)	2,109	2,138	2,281	2,125	2,160	2,343
Thus			—	2,686	2,516	2,392	2,696	2,379
Appliance Retailing	(i	)	—	2,946	2,743	2,391	2,988	2,762
United Kingdom total—discontinued operations	(ii	)	2,109	7,770	7,540	6,908	7,844	7,484
Total			16,162	21,981	24,114	21,183	22,407	24,287

The year end and average numbers of full-time equivalent staff employed by the group, including executive directors, were:

			At 31 March			Annual average
	Note		2002	2001	2000	2002	2001	2000
United Kingdom
—continuing operations			7,353	7,184	8,336	7,391	7,125	8,516
—discontinued operations	(ii	)	2,056	7,025	6,840	6,314	7,049	6,708
United States			6,349	6,612	7,742	6,474	6,993	7,791
Total			15,758	20,821	22,918	20,179	21,167	23,015

(i) As announced in May 2001, the group operates through three divisions which are different from the segments presented in the prior year’s Accounts. The former Generation Wholesale and Energy Supply segments have been combined and the former Other segment (other than Appliance Retailing) has been absorbed into the new UK business segments. Prior year comparatives have been restated accordingly. The previously reported year end and average number of employees (full-time and part-time) of the Other segment have been allocated as follows:

	At 31 March		Annual Average
	2001	2000	2001	2000
United Kingdom
UK Division—Generation, Trading and Supply	101	364	107	367
Infrastructure Division
Power Systems	84	1,150	91	1,197
Southern Water	35	138	37	140
Appliance Retailing	2,946	2,743	2,988	2,762
Other total	3,166	4,395	3,223	4,466

(ii) The annual average for 2002 for discontinued operations is calculated for the period prior to disposal or demerger. This represents the period to 8 October 2001 for Appliance Retailing and the period to 19 March 2002 for Thus.

(c)  Directors’ remuneration

Details, for each director, of remuneration, pension entitlements and interests in share options are set out on pages 51 to 54. This information forms part of the Accounts.

67

NOTES TO THE GROUP PROFIT AND LOSS ACCOUNT

for the year ended 31 March 2002—continued

4    Exceptional items

(a)  Recognised in arriving at operating profit

	Notes	2002 £m		2001 £m		2000 £m
Continuing operations
Reorganisation costs	(i), (iv), (v)	(18.5	)	(120.7	)	(40.4	)
Energy contracts	(vi)	—		—		(107.1	)
Impairment of assets	(vii)	—		—		(96.9	)
Total continuing operations		(18.5	)	(120.7	)	(244.4	)
Discontinued operations
Reorganisation costs	(v)	—		—		(14.6	)
Total recognised in arriving at operating profit		(18.5	)	(120.7	)	(259.0	)
(b)  Recognised after operating profit
Continuing operations
Share of joint venture impairment of assets		—		—		(3.3	)
Discontinued operations
Loss on disposal of and withdrawal from Appliance Retailing	(ii)	(120.1	)	—		—
Provision for loss on disposal of Southern Water before goodwill write back	(iii)	(449.3	)	—		—
Goodwill write back relating to Southern Water	(iii)	(738.2	)	—		—
Gain on partial disposal of Thus	(viii)	—		—		787.0
Loss on disposal of and withdrawal from other Telecoms operations	(ix)	—		—		(55.0	)
Total recognised after operating profit		(1,307.6	)	—		728.7
Total exceptional items before interest and taxation		(1,326.1	)	(120.7	)	469.7
Restructuring of debt portfolio	(iii), (ix)	(30.8	)	—		(15.9	)
Tax on exceptional items		38.8		45.9		(56.0	)
Total exceptional items (net of tax)		(1,318.1	)	(74.8	)	397.8

Year ended 31 March 2002

(i) An exceptional charge of £18.5 million was incurred relating to reorganisation costs for the UK Division—Generation, Trading and Supply and primarily represents severance and related costs.

(ii) An exceptional charge of £120.1 million relates to the loss on disposal of and withdrawal from the group’s Appliance Retailing operations. This charge includes £15.1 million of goodwill previously written off to reserves. The pre-goodwill loss of £105.0 million comprises asset impairments of £54.2 million (including a provision for impairment of tangible fixed assets of £32.2 million) and provisions for trading losses and closure costs of £50.8 million, of which £43.5 million had been incurred by 31 March 2002. The loss on disposal of and withdrawal from Appliance Retailing is stated before a tax credit of £21.0 million.

(iii) On 23 April 2002, the group completed the sale of Aspen 4 Limited (the holding company of Southern Water plc) to First Aqua Limited for a total consideration, before expenses, of £2.05 billion including repayment and acquisition of intra-group non-trading indebtedness and assumption by First Aqua Limited of Southern Water’s non-trading debt due to third parties. An exceptional charge of £1,187.5 million relates to the provision for the loss on disposal of the group’s Southern Water business. This charge includes £738.2 million of goodwill previously written off to reserves. Net exceptional finance costs of £30.8 million were incurred comprising hedging and debt redemption costs associated with the proposed refinancing of Southern Water and the restructuring of the group’s debt portfolio in anticipation of the disposal of Southern Water. The provision for loss on disposal of Southern Water is stated before a tax credit of £2.9 million.

Year ended 31 March 2001

(iv) The charge of £120.7 million related to the cost of the Transition Plan for PacifiCorp announced on 4 May 2000 and primarily represented severance and related costs for approximately 1,600 employees.

Year ended 31 March 2000

(v) Following the regulatory price reviews in the United Kingdom electricity and water industries announced in November 1999, the group commenced restructuring a large part of its UK businesses. The exceptional costs principally comprised employee severance costs.

(vi) Exceptional charges were recorded for the onerous costs of contracted energy and fuel purchases which were not expected to be recoverable.

(vii) Provision was made for impairment of assets following an assessment of the group’s UK generation portfolio and the outcome of the regulatory price reviews in the United Kingdom electricity industry announced in November 1999.

(viii) In November 1999, the group made Global and Employee Offerings of shares in its internet and telecommunications services subsidiary, Thus plc. As a result of these offerings the group’s interest in the share capital of Thus was reduced from 100% to 50.1%. The gain on sale represented the difference between the carrying amount of the net assets of Thus before the reduction in the group’s interest and the carrying amount attributable to the group’s interest immediately after the reduction and taking into account the net proceeds received. The gain on disposal was after charging goodwill of £48.0 million of which £13.4 million represented goodwill previously written off to reserves. The gain on partial disposal of Thus was stated before a taxation charge of £80.0 million.

(ix) An exceptional charge of £47.5 million related to the costs arising as a result of the group’s decision, in July 1999, to withdraw from the use of fixed radio access telephony, including a provision for impairment of tangible fixed assets of £38.5 million. In November 1999, the group disposed of its mobile telephone business. There was no gain or loss on disposal after charging £1.9 million of goodwill relating to this business which was originally charged to reserves. In addition, during the year ended 31 March 2000 and prior to the disposal, an impairment of goodwill of £7.5 million in respect of this business was charged to the profit and loss account. Net exceptional finance costs of £15.9 million were incurred on the closing out of swaps and redemption of debt to restructure the group’s debt portfolio, consequent on the receipt of the Thus sale proceeds.

68

5    Net interest and similar charges

	Notes	2002 £m		2001 £m		2000 £m
Analysis of net interest and similar charges
Interest on bank loans and overdrafts		32.8		38.1		24.6
Interest on other borrowings		379.5		333.7		235.2
Finance leases		2.3		2.2		0.7
Total interest payable		414.6		374.0		260.5
Interest receivable		(15.0	)	(33.7	)	(9.6	)
Capitalised interest		(36.1	)	(32.2	)	(28.8	)
Net interest charge		363.5		308.1		222.1
Unwinding of discount on provisions		22.8		16.0		5.4
Foreign exchange (gain)/loss		(6.9	)	8.8		—
Net interest and similar charges before exceptional items		379.4		332.9		227.5
Exceptional interest on bank loans and overdrafts		12.0		—		—
Exceptional interest on other borrowings		18.8		—		15.9
Exceptional interest and similar charges	4(iii), 4(ix)	30.8		—		15.9
Net interest and similar charges after exceptional items		410.2		332.9		243.4
Interest cover (times)		2.5		3.0		4.2

Interest cover is calculated by dividing profit on ordinary activities before interest (before exceptional items and goodwill amortisation) by the sum of the net interest charge (before exceptional interest and similar charges) and the unwinding of discount on provisions.

6    Tax on (loss)/profit on ordinary activities

	Before exceptional items 2002 £m		Exceptional items 2002 £m		2002 £m		Before exceptional item 2001 £m		Exceptional item 2001 £m		2001 £m		Before exceptional items 2000 £m		Exceptional items 2000 £m	2000 £m
Current tax:
UK Corporation tax	82.6		(32.5	)	50.1		175.3		—		175.3		165.8		56.0	221.8
Foreign tax	17.3		—		17.3		5.7		(8.7	)	(3.0	)	26.1		—	26.1
Double taxation relief	—		—		—		(61.2	)	—		(61.2	)	—		—	—
	99.9		(32.5	)	67.4		119.8		(8.7	)	111.1		191.9		56.0	247.9
Adjustments to UK Corporation tax in respect of prior years	(54.4	)	—		(54.4	)	(29.7	)	—		(29.7	)	(30.2	)	—	(30.2	)
Total current tax for year	45.5		(32.5	)	13.0		90.1		(8.7	)	81.4		161.7		56.0	217.7
Deferred tax:
Origination and reversal of timing differences	76.5		(6.3	)	70.2		86.0		(37.2	)	48.8		45.2		—	45.2
Adjustments in respect of prior years	—		—		—		(35.0	)	—		(35.0	)	—		—	—
Total deferred tax for year	76.5		(6.3	)	70.2		51.0		(37.2	)	13.8		45.2		—	45.2
Tax on (loss)/profit on ordinary activities	122.0		(38.8	)	83.2		141.1		(45.9	)	95.2		206.9		56.0	262.9
Effective rate of tax before goodwill amortisation	21.5	%					22.5	%					28.1	%

The current tax charge on (loss)/profit on ordinary activities for the year varied from the standard rate of UK Corporation tax as follows:

	2002 £m		2001 £m		2000 £m
Corporation tax at 30%	(281.6	)	113.9		344.7
Losses and other permanent differences	28.1		6.2		8.3
Effect of tax rate applied to overseas earnings	(21.8	)	11.2		8.1
Permanent differences on exceptional items	368.2		(9.7	)	(80.1	)
Goodwill amortisation	44.7		38.3		12.1
Adjustments in respect of prior years	(54.4	)	(64.7	)	(30.2	)
Tax charge (current and deferred)	83.2		95.2		262.9
Origination and reversal of timing differences—deferred tax charge	(70.2	)	(13.8	)	(45.2	)
Current tax charge for year	13.0		81.4		217.7

69

NOTES TO THE GROUP PROFIT AND LOSS ACCOUNT

for the year ended 31 March 2002—continued

7    (Loss)/earnings per ordinary share

(a)  (Loss)/earnings per ordinary share have been calculated for all years by dividing the (loss)/profit for the financial year by the weighted average number of ordinary shares in issue during the financial year, based on the following information:

	2002		2001	2000
(Loss)/profit for the financial year (£ million)	(987.1	)	307.5	885.0
Basic weighted average share capital (number of shares, million)	1,837.8		1,830.3	1,389.6
Diluted weighted average share capital (number of shares, million)	1,840.1		1,837.4	1,399.2

The difference between the basic and the diluted weighted average share capital is wholly attributable to outstanding share options and shares held in trust for the group’s Employee Share Ownership Plan. These share options are dilutive by reference to continuing operations and accordingly a diluted (loss)/earnings per share has been calculated which has the impact of reducing the net (loss)/earnings per ordinary share.

(b)  The calculation of (loss)/earnings per ordinary share, on a basis which excludes exceptional items and goodwill amortisation, is based on the following adjusted earnings:

	2002 £m		2001 £m	2000 £m
(Loss)/profit for the financial year	(987.1	)	307.5	885.0
Adjusting items—exceptional items (net of attributable taxation)	1,318.1		74.8	(397.8	)
—goodwill amortisation	149.0		127.6	40.4
Adjusted earnings	480.0		509.9	527.6

Adjusted earnings per share has been presented in addition to earnings per share calculated in accordance with FRS 14 in order that more meaningful comparisons of financial performance can be made.

8    Dividends

(a)  Cash dividends

	2002 pence per ordinary share	2001 pence per ordinary share	2000 pence per ordinary share	2002 £m	2001 £m	2000 £m
First interim dividend paid	6.835	6.51	8.27	125.4	119.1	95.2
Second interim dividend paid	6.835	6.51	8.10	125.9	119.3	92.1
Third interim dividend paid	6.835	6.51	2.23	126.1	119.5	40.7
Final dividend	6.835	6.51	6.20	126.1	119.4	113.4
Total cash dividends	27.34	26.04	24.80	503.5	477.3	341.4

(b)  Dividends in specie on demerger of Thus

	Note	2002 £m	2001 £m	2000 £m
Demerger dividend	33	436.6	—	—

        The demerger of Thus was recorded in the group Accounts at the book value of the net assets which were deconsolidated, of £421.9 million, together with £14.7 million of related goodwill which had previously been written off to reserves, giving a dividend in specie of £436.6 million.

The demerger of Thus was recorded in the individual company Accounts of Scottish Power plc at the book value of the cost of investment in the ordinary and preference shares of Thus, giving a dividend in specie of £396.3 million.

70

GROUP CASH FLOW STATEMENT

for the year ended 31 March 2002

	Notes	2002 £m		2001 £m		2000 £m
Cash inflow from operating activities	10	1,248.4		1,411.6		1,117.5
Dividends received from joint ventures		0.3		2.1		0.5
Returns on investments and servicing of finance	9	(377.8	)	(373.5	)	(258.4	)
Taxation		(85.0	)	(152.6	)	(154.3	)
Free cash flow		785.9		887.6		705.3
Capital expenditure and financial investment	9	(1,148.3	)	(1,081.4	)	(842.3	)
Cash flow before acquisitions and disposals		(362.4	)	(193.8	)	(137.0	)
Acquisitions and disposals	9	150.0		482.9		718.8
Equity dividends paid		(496.8	)	(471.3	)	(406.0	)
Cash (outflow)/inflow before use of liquid resources and financing		(709.2	)	(182.2	)	175.8
Management of liquid resources	9,13	(38.7	)	(11.9	)	(9.8	)
Financing
—Issue of ordinary share capital (net of costs)	9	16.2		6.6		(29.2	)
—issue of ordinary share capital by a subsidiary (net of costs)		—		—		310.0
—Share buy-back (including costs)	9	—		—		(302.0	)
—Redemption of preferred stock of PacifiCorp	9	(69.5	)	—		—
—Increase/(decrease) in debt	9,13	982.4		189.5		(100.0	)
		929.1		196.1		(121.2	)
Increase in cash in year	13	181.2		2.0		44.8

Free cash flow represents cash flow from operating activities after adjusting for dividends received from joint ventures, returns on investments and servicing of finance and taxation.

RECONCILIATION OF NET CASH FLOW TO MOVEMENT IN NET DEBT

for the year ended 31 March 2002

	Note	2002 £m		2001 £m		2000 £m
Increase in cash in year		181.2		2.0		44.8
Cash (inflow)/outflow from (increase)/decrease in debt		(982.4	)	(189.5	)	100.0
Cash outflow from movement in liquid resources		38.7		11.9		9.8
Change in net debt resulting from cash flows		(762.5	)	(175.6	)	154.6
Net debt acquired		—		—		(2,565.6	)
Net (funds)/debt disposed		(46.9	)	—		8.5
Exchange		(6.3	)	(264.7	)	(17.3	)
Other non-cash movements		(107.6	)	(3.3	)	(0.5	)
Movement in net debt in year		(923.3	)	(443.6	)	(2,420.3	)
Net debt at end of previous year		(5,285.1	)	(4,841.5	)	(2,421.2	)
Net debt at end of year	13	(6,208.4	)	(5,285.1	)	(4,841.5	)

The Accounting Policies and Definitions on pages 56 to 60, together with the Notes on pages 65 to 70, 72 to 74, 76 to 107 and 109 to 110 form part of these Accounts.

71

NOTES TO THE GROUP CASH FLOW STATEMENT

for the year ended 31 March 2002

9    Analysis of cash flows

(a)  Returns on investments and servicing of finance

	2002 £m		2001 £m		2000 £m
Interest received	33.1		32.7		9.7
Interest paid	(402.8	)	(395.8	)	(265.7	)
Dividends paid to minority interests	(8.1	)	(10.4	)	(2.4	)
Net cash outflow for returns on investments and servicing of finance	(377.8	)	(373.5	)	(258.4	)
(b)  Capital expenditure and financial investment
Purchase of tangible fixed assets	(1,244.7	)	(1,143.6	)	(917.7	)
Deferred income received	76.9		97.3		55.5
Sale of tangible fixed assets	17.7		26.4		26.5
Sale/(purchase) of fixed asset investments	1.8		(61.5	)	(6.6	)
Net cash outflow for capital expenditure and financial investment	(1,148.3	)	(1,081.4	)	(842.3	)
(c)  Acquisitions and disposals
Purchase of businesses and subsidiary undertakings	—		(230.2	)	2.1
Sale of businesses and subsidiary undertakings	150.0		713.1		(3.7	)
Partial disposal of Thus	—		—		720.4
Net cash inflow from acquisitions and disposals	150.0		482.9		718.8
(d)  Management of liquid resources*
Cash outflow in relation to short-term deposits and other short-term investments	(38.7	)	(11.9	)	(9.8	)
Net cash outflow for management of liquid resources	(38.7	)	(11.9	)	(9.8	)
(e)  Financing
Issue of ordinary share capital	16.2		6.6		3.8
Expenses paid in connection with share issue	—		—		(33.0	)
Issue of ordinary share capital by a subsidiary	—		—		327.0
Expenses paid in connection with share issue by a subsidiary	—		—		(17.0	)
Share buy-back	—		—		(302.0	)
Redemption of preferred stock of PacifiCorp	(69.5	)	—		—
	(53.3	)	6.6		(21.2	)
Debt due within one year:
—net drawdown/(repayment) of uncommitted facilities	120.8		6.6		(75.0	)
—drawdown of committed bank loan	100.0		—		—
—net commercial paper (redeemed)/issued	(52.8	)	6.1		(285.8	)
—medium-term notes/private placements	79.9		(58.9	)	(3.3	)
—(redemption)/issue of loan notes	(0.1	)	0.4		(8.0	)
—European Investment Bank loans	114.8		(4.6	)	0.8
—mortgages	72.6		(96.4	)	4.2
—non-recourse notes	—		(147.2	)	—
—5.875% euro-US dollar bond 2003	183.5		—		—
—other	(1.3	)	0.5		—
Debt due after one year:
—net repayment of uncommitted facilities	(3.8	)	—		—
—medium-term notes/private placements	7.5		594.2		178.1
—European Investment Bank loans	(129.2	)	42.8		86.2
—5.875% euro-US Dollar bond	(183.3	)	—		—
—11.457% sterling bond issue	—		—		(142.0	)
—6.625% euro-sterling bond issue	—		—		197.9
—variable coupon Australian dollar bond issue	233.8		—		—
—mortgages	449.5		(25.8	)	(53.1	)
—secured pollution control revenue bonds	2.8		0.2		—
—unsecured pollution control revenue bonds	(2.9	)	1.9		—
—junior debentures	—		(117.0	)	—
—non-recourse notes	—		(21.2	)	—
—other	(9.7	)	8.0		—
Finance leases:
—finance leases	0.3		(0.1	)	—
Increase/(decrease) in debt	982.4		189.5		(100.0	)
Net cash inflow/(outflow) from financing	929.1		196.1		(121.2	)

* Liquid resources include term deposits of less than one year, commercial paper and other short-term investments.

72

10    Reconciliation of operating profit to net cash inflow from operating activities

	2002 £m		2001 £m		2000 £m
Operating profit	776.6		721.9		662.0
Depreciation and amortisation	717.0		607.9		457.6
Profit on sale of tangible fixed assets and disposal of businesses	(7.7	)	(19.9	)	(19.8	)
Release of deferred income	(17.8	)	(15.1	)	(15.6	)
Movements in provisions for liabilities and charges	(93.6	)	57.5		103.1
Decrease/(increase) in stocks	10.4		(13.3	)	20.1
Decrease/(increase) in debtors	58.4		(137.2	)	(32.1	)
(Decrease)/increase in creditors	(194.9	)	209.8		(57.8	)
Net cash inflow from operating activities	1,248.4		1,411.6		1,117.5

11    Effect of disposals and acquisitions on cash flows

	Disposals 2002 £m		Acquisition 2000 £m
Cash (outflow)/inflow from operating activities	(39.5	)	242.4
Returns on investments and servicing of finance	0.7		(40.6	)
Taxation	—		7.6
Capital expenditure and financial investment	(93.2	)	(103.1	)
Acquisitions and disposals	3.3		—
Equity dividends paid	—		(9.8	)
Management of liquid resources	4.0		—
Financing	—		(71.0	)
(Decrease)/increase in cash	(124.7	)	25.5

The effect of disposals on cash flows in 2002 principally relates to the group’s demerger of Thus and the disposal of and withdrawal from Appliance Retailing. The cash flows relating to acquisitions during 2002 were not material.

The effect of acquisitions and disposals on cash flows during 2001 was not material. The analysis of cash flows of the acquisition in 2000 relates to the post-acquisition cash flows of PacifiCorp. The cash flows relating to the disposal during 2000 were not material.

12    Analysis of cash flows in respect of disposals and acquisitions

	Disposals 2002 £m		Acquisitions 2001 £m		Disposals 2001 £m		Acquisition 2000 £m		Disposal 2000 £m
Cash consideration including expenses	13.9		(227.7	)	716.5		(28.4	)	—
Cash at bank and in hand (disposed)/acquired	(9.2	)	—		—		41.4		(3.7	)
Pre-completion dividend to former PacifiCorp shareholders	—		—		—		(9.8	)	—
Deferred consideration in respect of prior year disposals/(acquisitions)	152.1		(2.5	)	—		(1.1	)	—
Expenses paid in respect of prior year disposals	(6.8	)	—		(3.4	)	—		—
	150.0		(230.2	)	713.1		2.1		(3.7	)

In 2002, the cash flows in respect of disposals principally represent the collection of a note receivable on the discontinued operations of PacifiCorp’s mining and resource development business, NERCO, which was sold in 1993 and the disposal of PacifiCorp’s synthetic fuel operations.

In 2001, cash flows in respect of acquisitions principally represent the purchase of Rye House power station. The cash flows in respect of disposals mainly comprise proceeds from the sale of Centralia and Powercor.

In 2000, acquisition cash flows principally represent the purchase of PacifiCorp and disposal cash flows represent proceeds received on the sale of other Telecoms operations.

The cash flows arising on the group’s partial disposal of its interest in Thus (net of expenses) were as follows:

	2000 £m
Cash received on primary issue by Thus	310.0
Cash received on sale of shares by ScottishPower	720.4
Total	1,030.4

73

NOTES TO THE GROUP CASH FLOW STATEMENT

for the year ended 31 March 2002—continued

13    Analysis of net debt

	At 1 April 2000 £m		Cash flow £m		Exchange £m		Other non-cash changes £m		At 31 March 2001 £m
2000/01
Cash at bank	106.7		13.1		19.9		—		139.7
Overdrafts	(39.1	)	(11.1	)	(2.3	)	—		(52.5	)
			2.0
Debt due after 1 year	(4,317.6	)	(474.0	)	(267.8	)	191.1		(4,868.3	)
Debt due within 1 year	(653.0	)	284.4		(12.4	)	(194.4	)	(575.4	)
Finance leases	(17.1	)	0.1		(2.1	)	—		(19.1	)
			(189.5	)
Other deposits	78.6		11.9		—		—		90.5
Total	(4,841.5	)	(175.6	)	(264.7	)	(3.3	)	(5,285.1	)

‘Other non-cash changes’ to net debt represents the movement in debt of £194.4 million due after more than one year to due within one year, amortisation of finance costs of £0.5 million and finance costs of £2.8 million representing the effects of the Retail Price Index (“RPI”) on bonds carrying an RPI coupon.

	At 1 April 2001 £m		Cash flow £m		Disposal (excl. cash & overdrafts) £m		Exchange £m		Other non-cash changes £m		At 31 March 2002 £m
2001/02
Cash at bank	139.7		163.4		—		(0.3	)	—		302.8
Overdrafts	(52.5	)	17.8		—		0.1		—		(34.6	)
			181.2
Debt due after 1 year	(4,868.3	)	(364.7	)	—		(3.7	)	(106.3	)	(5,343.0	)
Debt due within 1 year	(575.4	)	(617.4	)	4.4		(2.5	)	(1.3	)	(1,192.2	)
Finance leases	(19.1	)	(0.3	)	—		—		—		(19.4	)
			(982.4	)
Other deposits	90.5		38.7		(51.3	)	0.1		—		78.0
Total	(5,285.1	)	(762.5	)	(46.9	)	(6.3	)	(107.6	)	(6,208.4	)

‘Other non-cash changes’ to net debt represents amortisation of finance costs of £1.5 million, finance costs of £5.6 million representing the effects of the RPI on bonds carrying an RPI coupon and the recognition of the share of debt in joint arrangements of £100.5 million.

74

GROUP BALANCE SHEET

as at 31 March 2002

	Notes	2002 £m		2001 £m
Fixed assets
Intangible assets	16	2,658.9		2,840.8
Tangible assets	17	11,652.3		11,920.8
Investments
—Investments in joint ventures:
Share of gross assets		119.3		118.4
Share of gross liabilities		(82.4	)	(74.6	)
		36.9		43.8
—Investments in associates		5.2		5.0
—Other investments		223.5		247.5
	18	265.6		296.3
		14,576.8		15,057.9
Current assets
Stocks	19	167.0		215.1
Debtors
—Gross debtors		1,448.2		1,758.2
—Less non-recourse financing		(257.4	)	(285.7	)
	20	1,190.8		1,472.5
Short-term bank and other deposits		380.8		230.2
		1,738.6		1,917.8
Creditors:  amounts falling due within one year
Loans and other borrowings	21	(1,226.8	)	(627.9	)
Other creditors	22	(1,951.9	)	(2,375.9	)
		(3,178.7	)	(3,003.8	)
Net current liabilities		(1,440.1	)	(1,086.0	)
Total assets less current liabilities		13,136.7		13,971.9
Creditors: amounts falling due after more than one year
Loans and other borrowings	21	(5,362.4	)	(4,887.4	)
Provisions for liabilities and charges
—Deferred tax	24	(1,691.2	)	(1,625.3	)
—Other provisions	23	(713.8	)	(778.7	)
		(2,405.0	)	(2,404.0	)
Deferred income	25	(551.2	)	(501.5	)
Net assets	14	4,818.1		6,179.0
Called up share capital	26, 27	926.3		924.5
Share premium	27	2,254.1		3,739.7
Revaluation reserve	27	45.5		217.1
Capital redemption reserve	27	18.3		18.3
Merger reserve	27	406.4		406.4
Profit and loss account	27	1,080.8		587.2
Equity shareholders’ funds	27	4,731.4		5,893.2
Minority interests (including non-equity)	28	86.7		285.8
Capital employed		4,818.1		6,179.0
Net asset value per ordinary share	15	254.8	p	318.7	p

Approved by the Board on 1 May 2002 and signed on its behalf by

Charles Miller Smith Chairman David Nish Finance Director

        The Accounting Policies and Definitions on pages 56 to 60, together with the Notes on pages 65 to 70, 72 to 74, 76 to 107 and 109 to 110 form part of these Accounts.

75

NOTES TO THE GROUP BALANCE SHEET

as at 31 March 2002

14    Segmental information

(a)  Net assets by segment

	Notes	2002 £m		2001 £m
United Kingdom
UK Division—Generation, Trading and Supply	(i), (iv)	873.4		691.2
Infrastructure Division—Power Systems	(i), (iv)	2,070.7		1,979.0
United Kingdom total—continuing operations		2,944.1		2,670.2
United States—continuing operations
US Division—PacifiCorp	(iv)	7,776.0		7,778.7
Total continuing operations		10,720.1		10,448.9
United Kingdom—discontinued operations
Infrastructure Division—Southern Water	(i), (iv)	2,347.6		2,590.4
Thus	(ii), (iv)	—		459.3
Appliance Retailing	(i), (iv)	—		55.6
Total discontinued operations		2,347.6		3,105.3
Unallocated net liabilities
Net debt		(6,208.4	)	(5,285.1	)
Deferred tax		(1,691.2	)	(1,625.3	)
Corporate tax		(293.3	)	(365.0	)
Proposed dividend		(126.1	)	(119.4	)
Fixed asset investments		265.6		296.3
Other	(iii)	(196.2	)	(276.7	)
Total unallocated net liabilities		(8,249.6	)	(7,375.2	)
Total		4,818.1		6,179.0

(b)  Capital expenditure by segment (Note (v))

	Notes	2002 £m	2001 £m
United Kingdom
UK Division—Generation, Trading and Supply	(i)	109.2	160.1
Infrastructure Division—Power Systems	(i)	240.1	217.8
United Kingdom total—continuing operations		349.3	377.9
United States—continuing operations
US Division—PacifiCorp		599.4	328.8
Total continuing operations		948.7	706.7
United Kingdom—discontinued operations
Infrastructure Division—Southern Water	(i)	279.5	319.5
Thus	(ii)	78.0	158.9
Appliance Retailing	(i)	0.1	7.0
Total discontinued operations		357.6	485.4
Total		1,306.3	1,192.1

(c) Total assets by segment

	Notes	2002 £m	2001 £m
United Kingdom
UK Division—Generation, Trading and Supply	(i), (iv)	1,563.6	1,351.6
Infrastructure Division—Power Systems	(i), (iv)	2,657.6	2,503.0
United Kingdom total—continuing operations		4,221.2	3,854.6
United States—continuing operations
US Division—PacifiCorp	(iv)	8,878.9	9,052.7
Total continuing operations		13,100.1	12,907.3
United Kingdom—discontinued operations
Infrastructure Division—Southern Water	(i), (iv)	2,568.9	2,822.6
Thus	(ii),(iv)	—	589.2
Appliance Retailing	(i), (iv)	—	127.7
Total discontinued operations		2,568.9	3,539.5
Unallocated total assets	(vi)	646.4	528.9
Total		16,315.4	16,975.7

(i) As detailed in Note 1, the group now operates through three divisions which are different from the segments presented in the prior year’s Accounts. Prior year comparatives have been restated accordingly. The previously reported net assets, capital expenditure and total assets of the Other segment have been allocated as follows:

	Year ended 31 March 2001
	Net assets £m	Capital expenditure £m	Total assets £m
United Kingdom
UK Division–Generation, Trading and Supply	27.9	2.0	5.8
Infrastructure Division
Power Systems	2.3	0.8	4.9
Southern Water	1.5	—	—
Appliance Retailing	55.6	7.0	127.7
Other total	87.3	9.8	138.4

76

(ii) The segment previously described as ‘Telecoms’ has been redesignated ‘Thus’ as historical balance sheet data for this segment no longer includes data relating to other Telecoms operations disposed in prior years.

(iii) Other unallocated net liabilities principally includes interest.

(iv) As required by the Utilities Act 2000, the group has implemented a new legal entity structure for certain of its UK businesses to give effect to business separation. Following the creation of this new legal structure on 1 October 2001, the directors reviewed the group’s segments and concluded that no changes were required to the business segments disclosed above. However, they also reviewed the items to be included within each segment’s net assets and total assets particularly in relation to intra-group balances. The net assets and total assets by segment figures above have been presented on this revised basis and comparative figures have been restated accordingly.

(v) Capital expenditure by business segment is stated gross of capital grants and customer contributions. Capital expenditure net of contributions amounted to £1,229.4 million (2001 £1,094.8 million).

(vi) Unallocated total assets includes investments, interest receivable and bank deposits.

15    Net asset value per ordinary share

Net asset value per ordinary share has been calculated based on the following net assets and the number of shares in issue at the end of the respective financial years (after adjusting for the effect of shares held in trust for the group’s Sharesave Schemes and Employee Share Ownership Plan):

	31 March 2002	31 March 2001
Net assets (as adjusted) (£ million)	4,692.5	5,841.9
Number of ordinary shares in issue at year end (as adjusted) (number of shares, million)	1,841.9	1,833.0

16    Intangible fixed assets

Year ended 31 March 2001	Notes		Goodwill
			£m
Cost:
At 1 April 2000			2,228.5
Acquisition	(i	)	97.1
Revision to provisional fair values			414.0
Exchange			278.3
At 31 March 2001			3,017.9
Amortisation:
At 1 April 2000			40.1
Amortisation for the year			127.6
Exchange			9.4
At 31 March 2001			177.1
Net book value:
At 31 March 2001			2,840.8
At 31 March 2000			2,188.4
Year ended 31 March 2002			Goodwill
			£m
Cost:
At 1 April 2001			3,017.9
Thus open offer	33		34.4
Demerger of Thus	33		(70.4	)
Exchange			(4.1	)
At 31 March 2002			2,977.8
Amortisation:
At 1 April 2001			177.1
Amortisation for the year			149.0
Demerger of Thus	33		(7.8	)
Exchange			0.6
At 31 March 2002			318.9
Net book value:
At 31 March 2002			2,658.9
At 31 March 2001			2,840.8

(i) The provisional fair values attributed to the aquisition of Rye House in 2000/01, that resulted in goodwill of £97.1 million, have not required amendment in the post-acquisition period to March 2002.

Goodwill capitalised is being amortised over its estimated useful economic life of 20 years. Goodwill capitalised relating to Thus was being amortised over its estimated useful economic life of 15 years.

77

NOTES TO THE GROUP BALANCE SHEET

as at 31 March 2002—continued

17    Tangible fixed assets

Year ended 31 March 2001	Notes	Land and buildings £m		Water infrastructure assets £m		Plant and machinery £m		Vehicles and equipment £m		Total £m
Cost or valuation:
At 1 April 2000		1,217.8		1,093.7		8,838.5		1,280.7		12,430.7
Additions		115.4		90.5		739.2		247.0		1,192.1
Acquisitions		54.2		—		244.7		1.1		300.0
Revision to provisional fair values		—		—		(222.6	)	—		(222.6	)
Grants and contributions		—		(8.7	)	—		—		(8.7	)
Disposals		(24.5	)	(0.6	)	(75.3	)	(103.5	)	(203.9	)
Exchange		22.3		—		529.0		55.0		606.3
At 31 March 2001		1,385.2		1,174.9		10,053.5		1,480.3		14,093.9
Depreciation:
At 1 April 2000		237.0		68.1		1,135.9		306.4		1,747.4
Charge for the year		42.4		20.9		259.8		157.2		480.3
Disposals		(14.3	)	(0.6	)	(6.3	)	(50.5	)	(71.7	)
Exchange		0.5		—		12.5		4.1		17.1
At 31 March 2001		265.6		88.4		1,401.9		417.2		2,173.1
Net book value:
At 31 March 2001		1,119.6		1,086.5		8,651.6		1,063.1		11,920.8
At 31 March 2000		980.8		1,025.6		7,702.6		974.3		10,683.3
Year ended 31 March 2002
Cost or valuation:
At 1 April 2001		1,385.2		1,174.9		10,053.5		1,480.3		14,093.9
Additions		88.5		76.7		986.5		154.6		1,306.3
Impairment	(i),(ix)	(6.9	)	(306.3	)	(136.1	)	—		(449.3	)
Valuation adjustment	(ii)	—		(109.1	)	(207.3	)	—		(316.4	)
Grants and contributions		—		(9.2	)	—		—		(9.2	)
Disposals		(13.7	)	(0.6	)	(57.3	)	(94.9	)	(166.5	)
Demerger of Thus	33	(11.9	)	—		(466.2	)	(136.8	)	(614.9	)
Exchange		(0.3	)	—		(3.7	)	(0.5	)	(4.5	)
At 31 March 2002		1,440.9		826.4		10,169.4		1,402.7		13,839.4
Depreciation:
At 1 April 2001		265.6		88.4		1,401.9		417.2		2,173.1
Reclassification		(42.6	)	—		42.6		—		—
Charge for the year		32.8		21.2		323.1		177.9		555.0
Impairment	(ix)	1.6		—		12.2		31.4		45.2
Valuation adjustment	(ii)	—		(109.1	)	(207.3	)	—		(316.4	)
Disposals		(13.3	)	(0.5	)	(29.9	)	(80.9	)	(124.6	)
Demerger of Thus	33	(3.1	)	—		(78.9	)	(64.1	)	(146.1	)
Exchange		—		—		0.6		0.3		0.9
At 31 March 2002		241.0		—		1,464.3		481.8		2,187.1
Net book value:
At 31 March 2002		1,199.9		826.4		8,705.1		920.9		11,652.3
At 31 March 2001		1,119.6		1,086.5		8,651.6		1,063.1		11,920.8
								2002 £m		2001 £m
Historical cost analysis
Cost								13,785.4		13,941.9
Depreciation based on cost								(2,178.6	)	(2,238.2	)
Net book value based on cost								11,606.8		11,703.7

	Notes		2002 £m		2001 £m
Included in the cost or valuation of tangible fixed assets above are:
Assets in the course of construction			1,181.1		900.3
Other assets not subject to depreciation	(v	)	158.1		156.8
Grants and contributions in respect of water infrastructure assets			(42.2	)	(33.0	)
Capitalised interest	(iv	)	130.6		94.5

(i) The impairment of assets of £449.3 million represents the provision for loss on disposal of Southern Water. The total impairment of group assets is detailed in Note 1(c).

(ii) The valuation adjustment represents elimination of the accumulated depreciation on the tangible fixed assets of Southern Water which have been impaired.

(iii) The Manweb distribution and Southern Water operational assets were revalued by the directors on 30 September 1997 on a market value basis. The valuation of the Manweb distribution assets has not been and will not be updated, as permitted under the transitional provisions of FRS 15 ‘Tangible fixed assets’. The net book value of tangible fixed assets included at valuation at 31 March 2002 relates to Manweb distribution assets and was £599.6 million (2001 £2,198.1 million including Southern Water operational assets).

(iv) Interest on the funding attributable to major capital projects was capitalised during the year at a rate of 7% (2001 8%) in the United Kingdom and 4% (2001 7%) in the United States.

(v) Other assets not subject to depreciation are land. Land and buildings held by the group are predominantly freehold.

(vi) The historical cost of fully depreciated tangible fixed assets still in use was £272.6 million (2001 £224.6 million).

(vii) Capitalised computer software costs developed for internal use include employee, interest and other external direct costs of materials and services which are directly attributable to the development of computer software. Cumulative computer software costs capitalised are £490.7 million (2001 £455.5 million, 2000 £333.1 million). The depreciation charge was £109.3 million (2001 £52.5 million, 2000 £78.3 million including impairment).

78

(viii) The net book value of land and buildings under finance leases at 31 March 2002 was £22.3 million (2001 £28.0 million). The charge for depreciation against these assets during the year was £2.1 million (2001 £0.9 million).

(ix) Assets which were impaired in 2002 were valued on the basis of their estimated recoverable amounts. The impairment charge for the year ended 31 March 2002 of £494.5 million has been charged to the profit and loss account as follows: cost of sales £13.0 million, loss on disposal of and withdrawal from Appliance Retailing £32.2 million and provision for loss on disposal of Southern Water £449.3 million. The impairment charge for the year ended 31 March 2000 of £135.4 million was charged to the profit and loss account as follows: cost of sales £44.5 million, transmission and distribution costs £38.5 million, administrative expenses £13.9 million and loss on disposal of and withdrawal from other Telecoms operations, £38.5 million.

18    Fixed asset investments

	Note	Joint ventures				Associated undertakings Shares £m		Own shares held under trust £m		Other investments £m		Total £m
		Shares £m		Loans £m
Cost or valuation:
At 1 April 2000		0.3		19.3		5.4		70.4		137.2		232.6
Additions		23.7		16.8		—		7.5		32.1		80.1
Share of retained (loss)/profit		(4.8	)	(9.4	)	0.1		—		—		(14.1	)
Disposals and other		(0.4	)	(1.7	)	(0.5	)	(12.6	)	(3.7	)	(18.9	)
Exchange		—		—		—		0.1		16.5		16.6
At 31 March 2001		18.8		25.0		5.0		65.4		182.1		296.3
Additions		–		16.1		—		25.6		2.3		44.0
Share of retained (loss)/profit		(2.4	)	(0.5	)	0.2		–		—		(2.7	)
Disposals and other		(16.3	)	(3.8	)	—		(19.8	)	(7.7	)	(47.6	)
Demerger of Thus	33	—		—		—		—		(24.2	)	(24.2	)
Exchange		—		—		—		—		(0.2	)	(0.2	)
At 31 March 2002		0.1		36.8		5.2		71.2		152.3		265.6

The principal subsidiary undertakings, joint ventures and associated undertakings are listed on page 110.

Details of listed investments, including own shares held under trust, are given below:

	£m
Balance Sheet value at 31 March 2002	115.2
Market value at 31 March 2002	100.0

(a)  Shares in the company held under trust during the year are as follows:

2000/01	Notes		Dividends waived	Shares held at 1 April 2000 (000s)	Shares acquired during year (000s)	Shares transferred during year (000s)		Shares held at 31 March 2001 (000s)	Nominal value at 31 March 2001 £m	Market value at 31 March 2001 £m
Long Term Incentive Plan	(i	)	no	2,441	508	(237	)	2,712	1.4	12.7
ScottishPower Sharesave Schemes	(ii	)	yes	19,641	—	(4,401	)	15,240	7.6	71.3
PacifiCorp Stock Incentive Plan	(iv	)	no	58	131	(75	)	114	0.1	1.0
Employee Share Ownership Plan	(v	)	no	–	747	–		747	0.4	3.5
				22,140	1,386	(4,713	)	18,813	9.5	88.5
2001/02	Notes		Dividends waived	Shares held at 1 April 2001 (000s)	Shares acquired during year (000s)	Shares transferred during year (000s)		Shares held at 31 March 2002 (000s)	Nominal value at 31 March 2002 £m	Market value at 31 March 2002 £m
Long Term Incentive Plan	(i	)	no	2,712	1,355	(379	)	3,688	1.8	13.3
ScottishPower Sharesave Schemes	(ii	)	yes	15,240	—	(6,917	)	8,323	4.2	29.9
Executive Share Option Plan 2001	(iii	)	yes	—	2,360	—		2,360	1.2	8.5
PacifiCorp Stock Incentive Plan	(iv	)	no	114	122	(76	)	160	0.1	0.6
Employee Share Ownership Plan	(v	)	no	747	1,659	(224	)	2,182	1.1	7.8
				18,813	5,496	(7,596	)	16,713	8.4	60.1

(i) Shares of the company are held under trust as part of the Long Term Incentive Plan for executive directors and other senior managers (see Remuneration Report of the Directors on pages 48 to 54 for details of the Plan).

(ii) Shares of the company are held in two Qualifying Employee Share Ownership Trusts as part of the Scottish Power UK plc Sharesave Scheme, the Scottish Power plc Sharesave Scheme and the Southern Water Sharesave Scheme. Holders of options granted under the schemes will be awarded shares by the Trusts upon the exercise of the options. Details of options granted under these schemes are disclosed in Note 26.

(iii) Shares of the company are held under trust as part of the Executive Share Option Plan 2001 for executive directors and other senior managers (see Remuneration Report of the Directors on pages 48 to 54 for details of the Plan).

(iv) Options granted under the PacifiCorp Stock Incentive Plan are for ScottishPower ADSs; for the purposes of the table above, options have been converted to ScottishPower ordinary shares as follows: one ScottishPower ADS equals four ScottishPower ordinary shares.

(v) Shares of the company are held in the Employee Share Ownership Plan Trust on behalf of employees of the ScottishPower group. Shares appropriated under the Free Element and the Matching Element are subject to forfeiture for a period of three years from the date of appropriation. Shares appropriated under the Partnership Element of the Employee Share Ownership Plan are not subject to forfeiture.

19    Stocks

	2002 £m	2001 £m
Raw materials and consumables	95.7	103.7
Fuel stocks	48.4	53.1
Work in progress	21.7	8.2
Finished goods and goods for resale	1.2	50.1
	167.0	215.1

79

NOTES TO THE GROUP BALANCE SHEET

as at 31 March 2002—continued

20    Debtors

	Notes	2002 £m		2001 £m
(a)  Amounts falling due within one year:
Trade debtors	(i)	470.9		620.0
Amounts receivable under finance leases—US	(ii), (iii)	124.1		42.3
Less non-recourse financing		(92.9	)	(22.4	)
		31.2		19.9
Amounts receivable under finance leases—UK	(iii)	0.1		0.3
Prepayments and accrued income		395.2		428.1
Other debtors		114.7		55.8
		1,012.1		1,124.1
(b)  Amounts falling due after more than one year:
Amounts receivable under finance leases—US	(ii), (iii)	318.0		459.0
Less non-recourse financing		(164.5	)	(263.3	)
		153.5		195.7
Amounts receivable under finance leases—UK	(iii)	4.2		2.2
Other debtors		21.0		150.5
		1,190.8		1,472.5

   (i) Trade debtors are stated net of provisions for doubtful debts of £101.1 million (2001 £80.2 million).

  (ii) The group’s finance lease assets in the United States which are financed by non-recourse borrowing qualify for linked presentation under FRS 5. The provider of the finance has agreed in writing in the finance documentation that it will seek repayment of the finance, as to both principal and interest, only to the extent that sufficient funds are generated by the specific assets it has financed and that it will not seek recourse in any other form. The directors confirm that the group has no obligation to support any losses arising under these leases nor is there any intention to do so.

(iii) Amounts receivable under finance leases falling due after more than one year at 31 March 2002 of £322.2 million (2001 £461.2 million) are due as follows: within 1-2 years, £28.7 million (2001 £120.9 million); within 2-3 years, £36.8 million (2001 £49.8 million); within 3-4 years, £28.6 million (2001 £37.1 million); within 4-5 years, £38.3 million (2001 £28.9 million) and after 5 years, £189.8 million (2001 £224.5 million). Total amounts receivable under finance leases during the year were £58.8 million (2001 £62.1 million).

21    Loans and other borrowings

Details of the group’s objectives, policies and strategy with regard to financial instruments and risk management are contained within the Financial Review on pages 30 to 43. The analyses of financial instruments in this Note, other than currency disclosures, do not include short-term debtors and creditors as permitted by FRS 13.

(a)  Analysis by instrument

	Notes		Weighted average interest rate 2002		Weighted average interest rate 2001		2002 £m	2001 £m
Unsecured debt of UK businesses
Bank overdraft			—		—		11.0	23.6
Committed bank loans			5.0	%	—		100.0	—
Uncommitted bank loans			5.0	%	6.0	%	212.9	96.0
Commercial paper	(i	)	5.0	%	6.0	%	195.0	203.8
Medium-term notes/private placements	(ii	)	5.6	%	6.5	%	1,245.1	1,151.3
Loan notes	(iii	)	4.9	%	6.2	%	5.9	9.1
European Investment Bank loans	(iv	)	6.8	%	7.2	%	328.4	342.8
5.875% euro-US dollar bond 2003			7.0	%	6.9	%	183.5	183.4
Variable coupon bond 2008			6.9	%	6.9	%	99.8	99.7
Variable rate Australian dollar bond 2011			5.7	%	—		233.8	—
5.250% deutschmark bond 2008			6.8	%	6.8	%	245.7	245.7
6.625% euro-sterling bond 2010			6.7	%	6.6	%	198.2	198.1
8.375% euro-sterling bond 2017			8.4	%	8.4	%	197.5	197.1
6.750% euro-sterling bond 2023			6.8	%	6.8	%	247.1	247.1
Unsecured debt of US businesses
Bank overdraft			—		—		23.6	28.9
Commercial paper	(i	)	2.2	%	6.2	%	124.0	169.1
Preferred securities	(v	)	8.6	%	8.6	%	231.9	232.1
Pollution control revenue bonds	(vi	)	2.1	%	3.5	%	316.4	315.2
Finance leases	(vii	)	11.9	%	11.9	%	19.4	19.1
Unsecured debt							4,219.2	3,762.1
Secured debt of US businesses
First mortgage and collateral bonds	(viii	)	7.5	%	7.6	%	2,011.1	1,486.4
Pollution control revenue bonds	(vi	)	2.6	%	3.7	%	198.9	198.8
Other secured borrowings	(ix	)	6.6	%	7.2	%	160.0	68.0
							2,370.0	1,753.2
							6,589.2	5,515.3

80

(i) Commercial paper

Scottish Power UK plc has an established US$2.0 billion (2001 US$2.0 billion) euro-commercial paper programme. Paper is issued in a range of currencies and swapped back into sterling. PacifiCorp has a US$1.5 billion domestic commercial paper programme and PacifiCorp Group Holdings has a US$200.0 million domestic commercial paper programme. Amounts borrowed under the commercial paper programmes are repayable in less than one year.

(ii) Medium-term notes/private placements

Scottish Power UK plc has an established US$7.0 billion (2001 US$4.0 billion) euro-medium-term note programme. Scottish Power plc has been added as an issuer under the programme, although no issues have yet been transacted. Paper is issued in a range of currencies and swapped back into sterling. As at 31 March 2002, maturities range from 1 to 38 years.

(iii) Loan notes

All loan notes are redeemable at the holders discretion. Ultimate maturity dates range from 2002 to 2006.

(iv) European Investment Bank (“EIB”) loans

These loans incorporate agreements with various interest rates and maturity dates. The maturity dates of these arrangements range from 2006 to 2011. Following the sale of Aspen 4 Limited (the holding company of Southern Water plc) in April 2002, the EIB loans relating to Southern Water were repaid.

(v) Preferred securities

Wholly-owned subsidiary trusts of PacifiCorp (“the Trusts”) have issued redeemable preferred securities representing preferred undivided beneficial interests in the assets of the Trusts. The sole assets of the Trusts are junior subordinated deferrable interest debentures of PacifiCorp that bear interest at the same rates as the preferred securities to which they relate, and certain rights under related guarantees by PacifiCorp.

(vi) Pollution control revenue bonds

Bonds issued by qualified tax exempt entities to finance, or refinance, the cost of certain pollution control, solid waste disposal and sewage facilities. PacifiCorp has entered into agreements with the issuers pursuant to which PacifiCorp received the proceeds of the issuance and agreed to make payments sufficient to pay principal of, interest on, and certain additional expenses. The interest on the bonds is not subject to federal income taxation for most bondholders. In some cases, PacifiCorp has issued first mortgage and collateral bonds as collateral for repayment.

(vii) Finance leases

These are facility leases that are accounted for as capital leases, maturity dates range from 2013 to 2022.

(viii) First mortgage and collateral bonds

First mortgage and collateral bonds of PacifiCorp may be issued in amounts limited by its Domestic Electric operation’s property, earnings and other provisions of the mortgage indenture. Approximately US$11.5 billion of the eligible assets (based on original costs) of PacifiCorp is subject to the lien of the mortgage.

(ix) Other secured borrowings

Included within other secured borrowings is ScottishPower’s share of debt in a joint arrangement for the Klamath co-generation plant. The borrowings are the subject of a guarantee, for US$60.0 million, provided by NA General Partnership in respect of second lien revenue bonds.

(b) Fair value of financial liabilities

	At 31 March 2002				At 31 March 2001
	Book amount £m		Fair value £m		Book amount £m		Fair value £m
Short-term debt and current portion of long-term debt	1,263.1		1,263.1		631.7		631.7
Long-term debt	5,356.0		5,555.2		4,918.3		5,097.5
Cross currency interest rate swaps	(29.9	)	(26.0	)	(34.7	)	(25.5	)
Total debt	6,589.2		6,792.3		5,515.3		5,703.7
Interest rate swaps	—		22.6		—		54.8
Interest rate swaptions	4.0		1.4		4.0		1.9
Forward rate agreements	—		—		—		0.1
Forward contracts	16.8		10.8		8.1		16.0
Energy hedge contracts	(0.3	)	60.3		—		—
Energy trading contracts	(1.0	)	(1.0	)	0.4		0.4
Total financial liabilities	6,608.7		6,886.4		5,527.8		5,776.9

The assumptions used to estimate fair values of debt and other financial instruments are summarised below:

(i) For short-term borrowings (uncommitted borrowing, commercial paper and short-term borrowings under the committed facilities), the book value approximates to fair value because of their short maturities.

(ii) The fair values of all quoted euro bonds are based on their closing clean market price converted at the spot rate of exchange as appropriate.

(iii) The fair values of the EIB loans have been calculated by discounting their future cash flows at market rates adjusted to reflect the redemption adjustments allowed under each agreement.

(iv) The fair values of unquoted debt have been calculated by discounting the estimated cash flows for each instrument at the appropriate market discount rate in the currency of issue in effect at the balance sheet date.

(v) The fair values of the sterling interest rate swaps, sterling forward rate agreements and sterling interest rate caps have been estimated by calculating the present value of estimated cash flows.

(vi) The fair values of the sterling interest rate swaptions are estimated using the sterling yield curve and implied volatilities as at 31 March.

(vii) The fair values of the cross currency interest rate swaps have been estimated by adding the present values of the two sides of each swap. The present value of each side of the swap is calculated by discounting the estimated future cash flows for that side, using the appropriate market discount rates for that currency in effect at the balance sheet date.

(viii) The fair values of the forward contracts are estimated using market forward exchange rates on 31 March.

(ix) The fair values of gas futures are the margin calls under those contracts.

(x) The fair values of weather derivatives have been estimated assuming for water related derivatives a normal water year in several water basins, and for temperature related derivatives a normal daily high temperature of certain cities in the US.

81

NOTES TO THE GROUP BALANCE SHEET

as at 31 March 2002—continued

(c)  Maturity analysis

	2002 £m	2001 £m
Repayments fall due as follows:
Within one year, or on demand	1,226.8	627.9
After more than one year	5,362.4	4,887.4
	6,589.2	5,515.3
Repayments due after more than one year are analysed as follows:
Between one and two years	198.9	434.9
Between two and three years	238.6	213.7
Between three and four years	340.4	259.2
Between four and five years	259.5	349.2
More than five years	4,325.0	3,630.4
	5,362.4	4,887.4

Included in the between two and five years figures above is £0.6 million and in the more than five years figure is £18.8 million relating to finance leases (2001 £0.2 million and £19.1 million respectively).

	2003 £m		2004 £m		2005 £m		2006 £m		2007 £m		Thereafter £m		Total £m		Fair Value* £m
Liabilities
Fixed rate (GBP)	129.3		58.0		50.0		—		100.0		1,139.6		1,476.9		1,537.3
Average interest rate (GBP)	8.4	%	6.4	%	6.6	%	—		6.5	%	6.6	%	6.8	%
Fixed rate (USD)—UK group	183.5		—		—		—		—		51.4		234.9		272.8
Average interest rate (USD)—UK group	5.9	%	—		—		—		—		4.6	%	5.6	%
Fixed rate (USD)—US group	126.8		97.2		169.0		186.6		143.7		1,722.9		2,446.2		2,566.0
Average interest rate (USD)—US group	7.2	%	7.3	%	7.3	%	7.4	%	7.6	%	7.7	%	7.6	%
Fixed rate (CHF)	—		4.1		—		—		—		—		4.1		4.1
Average interest rate (CHF)	—		2.5	%	—		—		—		—		2.5	%
Fixed rate (CZK)	—		—		—		34.2		—		—		34.2		41.6
Average interest rate (CZK)	—		—		—		6.9	%	—		—		6.9	%
Fixed rate (EUR)	—		7.0		8.1		—		—		282.5		297.6		265.9
Average interest rate (EUR)	—		4.9	%	4.5	%	—		—		5.2	%	5.2	%
Fixed rate (JPY)	—		—		—		20.4		—		—		20.4		22.6
Average interest rate (JPY)	—		—		—		2.2	%	—		—		2.2	%
Index-linked (GBP)	—		—		—		—		—		181.5		181.5		183.5
Average interest rate (GBP)	—		—		—		—		—		3.49 x RPI		3.49 x RPI
Variable rate (GBP)	415.2		16.0		5.0		—		—		179.8		616.0		619.1
Average interest rate (GBP)	1m LIBOR		3m LIBOR		3m LIBOR		—		—		6m LIBOR		3m LIBOR
Variable rate (USD)—UK group	117.8		16.6		—		66.3		—		21.2		221.9		237.7
Average interest rate (USD)—UK group	3m LIBOR		6m LIBOR		—		3m LIBOR		—		3m LIBOR		3m LIBOR
Variable rate (USD)—US group	123.9		—		—		11.0		15.8		432.8		583.5		581.9
Average interest rate (USD)—US group	1m LIBOR		—		—		BMA		BMA		BMA		BMA
Variable rate (USD)—US group	—		—		—		—		—		55.6		55.6		55.6
Average interest rate (USD)—US group	—		—		—		—		—		MCBY		MCBY
Variable rate (AUD)	4.2		—		—		—		—		233.8		238.0		256.6
Average interest rate (AUD)	6m LIBOR		—		—		—		—		3m BBSW		3m BBSW
Variable rate (CHF)	5.0		—		—		—		—		—		5.0		4.2
Average interest rate (CHF)	3m LIBOR		—		—		—		—		—		3m LIBOR
Variable rate (EUR)	117.8		—		6.5		—		—		18.7		143.0		141.7
Average interest rate (EUR)	2m LIBOR		—		3m LIBOR		—		—		5m LIBOR		2m LIBOR
Variable rate (JPY)	3.3		—		—		21.9		—		5.2		30.4		27.7
Average interest rate (JPY)	2m LIBOR		—		—		6m LIBOR		—		6m LIBOR		6m LIBOR
													6,589.2		6,818.3

* Fair value represents the fair value of the total debt excluding the fair value of related cross currency interest rate swaps, details of which are set out in Note 21(g).

The average variable rates above, LIBOR, exclude margins. LIBOR is the London Inter Bank Offer Rate.

GBP—Pounds Sterling, USD—American Dollars, CHF—Swiss Francs, CZK—Czech Koruna, EUR— Euros, JPY—Japanese Yen, AUD—Australian Dollars, CAD—Canadian Dollars. BMA is a weekly high grade market index comprised of 7-day tax exempt variable rate demand notes produced by municipal market data. MCBY is the Moody’s Corporate Bond Yield. It is derived from the pricing data of 100 corporate bonds in the US market, each with current outstandings of over $100 million and maturities of 30 years. BBSW is the Australian Bank Bill Rate.

Reference to ‘m’ in ‘m LIBOR’ represents months.

82

(d)  Interest rate analysis

	At 31 March 2002			At 31 March 2001
	UK £m	US £m	Total £m 1/8	UK £m	US £m	Total £m
Fixed rate borrowings	1,920.2	2,446.2	4,366.4	2,090.1	1,801.9	3,892.0
Capped rate borrowings	—	—	—	150.0	—	150.0
Floating rate borrowings	1,583.7	639.1	2,222.8	757.6	715.7	1,473.3
	3,503.9	3,085.3	6,589.2	2,997.7	2,517.6	5,515.3

	Weighted average interest rate at which borrowings are fixed/capped				Weighted average period for which interest rate is fixed/capped
	At 31 March 2002		At 31 March 2001		At 31 March 2002		At 31 March 2001
	UK %	US %	UK %	US %	UK Years	US Years	UK Years	US Years
Fixed rate borrowings	6.9	7.6	7.1	7.8	10	13	10	13
Capped rate borrowings	—	—	7.0	—	—	—	1	—

All amounts in the analysis above take into account the effect of interest rate swaps and caps and currency swaps. Floating rate borrowings bear interest at rates based on LIBOR, certificate of deposit rates, interbank borrowing rates, prime rates or other short-term market rates. The average interest rates on short-term borrowings as at 31 March 2002 were as follows: UK operations 4.3%, US operations 2.2% (2001 6.0% and 5.7% respectively).

Based on the floating rate net debt of £2,222.8 million at 31 March 2002 (2001 £1,473.3 million), a 100 basis point change in interest rates would result in a £22.2 million change in (loss)/profit before tax for the year (2001 £14.7 million change).

(e)  Financial assets

	At 31 March 2002			At 31 March 2001
	UK £m	US £m	Total £m	UK £m	US £m	Total £m
Fixed rate financial assets	7.4	184.7	192.1	11.4	330.2	341.6
Floating rate financial assets	219.0	196.8	415.8	121.1	100.2	221.3
	226.4	381.5	607.9	132.5	430.4	562.9

Included within US fixed rate financial assets at 31 March 2002 are amounts receivable under finance leases of £442.1 million (2001 £501.3 million) less non-recourse finance of £257.4 million (2001 £285.7 million) and US fixed rate financial assets at 31 March 2001 included amounts relating to a finance note of £114.6 million which was repaid during the year. The floating rate financial assets of the group’s UK and US operations are principally cash deposits of which £2.1 million in the UK and £24.5 million in the US, are subject to either a legal assignment or a charge in favour of a third party.

	Weighted average interest rate at which financial assets are fixed				Weighted average period for which interest is fixed
	At 31 March 2002		At 31 March 2001		At 31 March 2002		At 31 March 2001
	UK %	US %	UK %	US %	UK Years	US Years	UK Years	US Years
Fixed rate financial assets	8.4	9.4	6.5	10.8	7	9	4	5

        All amounts in the analysis above take into account the effect of interest rate swaps and currency swaps. Floating rate investments pay interest at rates based on LIBOR, certificate of deposit rates, prime rates or other short-term market rates. The average interest rates on short-term financial assets as at 31 March 2002 were as follows: UK operations 3.7%, US operations 2.0% (2001 6.1% and 5.2% respectively).

The fair values of the financial assets are not materially different from their book values.

(f)  Borrowing facilities

The group has the following undrawn committed borrowing facilities at 31 March 2002 in respect of which all conditions precedent have been met. Of the facilities shown £1,000.0 million relates to operations in the UK. The remaining £618.0 million relates to operations in the US. Both facilities are floating rate facilities.

	At 31 March 2002 £m	At 31 March 2001 £m
Expiring within one year	618.0	1,351.7
Expiring between two and five years	1,000.0	—

Commitment fees on the above facilities were as follows: Scottish Power UK plc group £4.1 million (2001 £2.6 million); PacifiCorp group £0.6 million (2001 £0.5 million).

Following completion of the sale of Southern Water in April 2002, the £1,000.0 million Revolving Credit Facility of Scottish Power UK plc, included in the table above, was cancelled.

83

NOTES TO THE GROUP BALANCE SHEET

as at 31 March 2002—continued

(g) Maturity analysis of derivatives

	2003 £m		2004 £m		2005 £m		2006 £m		2007 £m		Thereafter £m		Total £m		Fair Value £m
Interest rate swaps
Variable to fixed (GBP)	125.0		100.0		—		—		50.0		50.0		325.0		8.4
Average pay rate	6.5	%	6.8	%	—		—		5.5	%	6.3	%	6.4	%
Average receive rate	4m LIBOR		4m LIBOR		—		—		3m LIBOR		3m LIBOR		4m LIBOR
Fixed to index-linked (GBP)	—		—		—		—		–		100.0		100.0		6.6
Average pay rate	—		—		—		—		–		3.35xRPI		3.35xRPI
Average receive rate	—		—		—		—		–		6.2	%	6.2	%
Fixed to variable (GBP)	—		50.0		150.0		50.0		220.0		1,062.0		1,532.0		8.1
Average pay rate	—		6m LIBOR		6m LIBOR		6m LIBOR		6m LIBOR		6m LIBOR		6m LIBOR
Average receive rate	—		5.0	%	5.7	%	5.3	%	5.9	%	6.3	%	6.1	%
Variable to variable (GBP)	—		—		5.0		—		—		30.0		35.0		(0.5	)
Average pay rate	—		—		6m LIBOR		—		—		6m LIBOR		6m LIBOR
Average receive rate	—		—		3m LIBOR		—		—		12m LIBOR		11m LIBOR
Swaptions
Notional amount (GBP)	—		—		—		—		—		100.0		100.0		1.4
Average pay rate	—		—		—		—		—		4.3	%	4.3	%
Average receive rate	—		—		—		—		—		6m LIBOR		6m LIBOR
Cross currency swaps					—		—		—		—
Receive fixed USD pay fixed GBP	183.7		—		—		—		—		—		183.7		(28.8	)
Average pay rate (GBP)	6.8	%	—		—		—		—		—		6.8	%
Average receive rate (USD)	5.9	%	—		—		—		—		—		5.9	%
Receive fixed USD pay variable GBP	—		—		—		—		—		51.4		51.4		(8.7	)
Average pay rate (GBP)	—		—		—		—		—		6m LIBOR		6m LIBOR
Average receive rate (USD)	—		—		—		—		—		4.6	%	4.6	%
Receive variable USD pay fixed GBP	—		—		—		33.1		—		21.2		54.3		(4.9	)
Average pay rate (GBP)	—		—		—		6.7	%	—		4.9	%	6.0	%
Average receive rate (USD)	—		—		—		3m LIBOR		—		3m LIBOR		3m LIBOR
Receive variable USD pay variable GBP	93.8		16.6		—		33.3		—		—		143.7		(14.3	)
Average pay rate (GBP)	4m LIBOR		6m LIBOR		—		6m LIBOR		—		—		5m LIBOR
Average receive rate (USD)	3m LIBOR		6m LIBOR		—		3m LIBOR		—		—		3m LIBOR
Receive variable AUD pay variable GBP	—		—		—		—		—		237.8		237.8		(7.1	)
Average pay rate (GBP)	—		—		—		—		—		6m LIBOR		6m LIBOR
Average receive rate (AUD)	—		—		—		—		—		3m BBSW		3m BBSW
Receive fixed CHF pay variable GBP	—		4.1		—		—		—		—		4.1		(0.1	)
Average pay rate (GBP)	—		3m LIBOR		—		—		—		—		3m LIBOR
Average receive rate (CHF)	—		2.7	%	—		—		—		—		2.7	%
Receive variable CHF pay variable GBP	5.0		—		—		—		—		—		5.0		0.9
Average pay rate (GBP)	6m LIBOR		—		—		—		—		—		6m LIBOR
Average receive rate (CHF)	3m LIBOR		—		—		—		—		—		3m LIBOR
Receive fixed CZK pay variable GBP	—		—		—		34.3		—		—		34.3		(7.2	)
Average pay rate (GBP)	—		—		—		6m LIBOR		—		—		6m LIBOR
Average receive rate (CZK)	—		—		—		6.9	%	—		—		6.9	%
Receive fixed EUR pay fixed GBP	—		—		—		—		—		246.6		246.6		32.2
Average pay rate (GBP)	—		—		—		—		—		6.7	%	6.7	%
Average receive rate (EUR)	—		—		—		—		—		5.3	%	5.3	%
Receive fixed EUR pay variable GBP	—		7.0		14.6		—		—		36.8		58.4		4.6
Average pay rate (GBP)	—		6m LIBOR		6m LIBOR		—		—		6m LIBOR		6m LIBOR
Average receive rate (EUR)	—		4.9	%	4.8	%	—		—		5.0	%	5.0	%
Receive variable EUR pay variable GBP	16.7		—		—		—		—		18.7		35.4		1.3
Average pay rate (GBP)	3m LIBOR		—		—		—		—		6m LIBOR		5m LIBOR
Average receive rate (EUR)	3m LIBOR		—		—		—		—		5m LIBOR		4m LIBOR
Receive fixed JPY pay variable GBP	—		—		—		20.4		—		—		20.4		(2.1	)
Average pay rate (GBP)	—		—		—		6m LIBOR		—		—		6m LIBOR
Average receive rate (JPY)	—		—		—		2.2	%	—		—		2.2	%
Receive variable JPY pay variable GBP	—		—		—		21.9		—		5.2		27.1		2.8
Average pay rate (GBP)	—		—		—		6m LIBOR		—		6m LIBOR		6m LIBOR
Average receive rate (JPY)	—		—		—		6m LIBOR		—		6m LIBOR		6m LIBOR
Receive fixed GBP pay fixed USD	—		—		70.0		—		—		—		70.0		(0.2	)
Average pay rate (USD)	—		—		4.1	%	—		—		—		4.1	%
Average receive rate (GBP)	—		—		5.2	%	—		—		—		5.2	%
Receive fixed GBP pay variable USD	—		—		—		—		35.0		—		35.0		0.5
Average pay rate (USD)	—		—		—		—		6m LIBOR		—		6m LIBOR
Average receive rate (GBP)	—		—		—		—		5.3	%	—		5.3	%
Receive variable GBP pay fixed USD	700.0		352.2		352.0		175.8		–		—		1,580.0		(39.1	)
Average pay rate (USD)	2.7	%	3.7	%	3.6	%	4.3	%	–		—		3.3	%
Average receive rate (GBP)	6m LIBOR		6m LIBOR		6m LIBOR		6m LIBOR		–		—		6m LIBOR
Receive variable GBP pay variable USD	—		—		105.3		317.0		105.7		2,107.7		2,635.7		44.2
Average pay rate (USD)	—		—		6m LIBOR		6m LIBOR		6m LIBOR		6m LIBOR		6m LIBOR
Average receive rate (GBP)	—		—		6m LIBOR		6m LIBOR		6m LIBOR		6m LIBOR		6m LIBOR
Forward contracts
Buy GBP, sell USD	768.5		267.5		108.5		—		—		—		1,144.5		10.6
Buy USD, sell GBP	160.9		—		—		—		—		—		160.9		(0.2	)
Buy GBP, sell CAD	20.9		—		—		—		—		—		20.9		0.1
Buy AUD, sell GBP	4.3		—		—		—		—		—		4.3		(0.2	)
Buy EUR, sell GBP	101.6		—		—		—		—		—		101.6		0.5
Buy JPY, sell GBP	3.3		—		—		—		—		—		3.3		—
													8,950.4		8.8

The abbreviations contained in the table are defined in Note 21(c). The above table includes derivatives relating to the partial hedging of the net assets of PacifiCorp and the implementation of the change in policy regarding the interest rate mix of the group’s debt.

84

(h)  Hedges

Gains and losses on instruments used for hedging are not recognised until the exposure that is being hedged is itself recognised. Unrecognised gains and losses on instruments used for hedging, and the movements therein, are as follows:

	Note		Gains £m		Losses £m		Total net gains/losses £m
Unrecognised gains and (losses) on hedges at 1 April 2000			51.9		(84.1	)	(32.2	)
Transfer from gains to losses	(i	)	(5.8	)	5.8		—
Transfer from losses to gains	(i	)	(4.5	)	4.5		—
(Gains) and losses arising in previous years that were recognised in 2000/01			(20.6	)	22.3		1.7
Gains and (losses) arising before 1 April 2000 that were not recognised in 2000/01			21.0		(51.5	)	(30.5	)
Gains and (losses) arising in 2000/01 that were not recognised in 2000/01			87.7		(127.1	)	(39.4	)
Unrecognised gains and (losses) on hedges at 31 March 2001			108.7		(178.6	)	(69.9	)
Gains and (losses) expected to be recognised in 2001/02			(4.6	)	(20.9	)	(25.5	)
Gains and (losses) expected to be recognised in 2002/03 or later			113.3		(157.7	)	(44.4	)

(i) Figures in the table above are calculated by reference to the 31 March 2001 fair value of the derivative concerned.

	Note		Gains £m		Losses £m		Total net gains/losses £m
Unrecognised gains and (losses) on hedges at 1 April 2001			108.7		(178.6	)	(69.9	)
Transfer from gains to losses	(ii	)	(0.2	)	0.2		—
Transfer from losses to gains	(ii	)	(0.1	)	0.1		—
(Gains) and losses arising in previous years that were recognised in 2001/02			3.3		8.2		11.5
Gains and (losses) arising before 1 April 2001 that were not recognised in 2001/02			111.7		(170.1	)	(58.4	)
Gains and (losses) arising in 2001/02 that were not recognised in 2001/02			(47.6	)	27.5		(20.1	)
Unrecognised gains and (losses) on hedges at 31 March 2002			64.1		(142.6	)	(78.5	)
Gains and (losses) expected to be recognised in 2002/03			14.4		(17.7	)	(3.3	)
Gains and (losses) expected to be recognised in 2003/04 or later			49.7		(124.9	)	(75.2	)

(ii) Figures in the table above are calculated by reference to the 31 March 2002 fair value of the derivative concerned.

(i)  Fair value of financial assets and liabilities held for trading

	2002 £m		2001 £m
Net realised and unrealised gains/(losses) included in profit and loss account	4.5		(0.3	)
Fair value of financial assets held for trading at 31 March	3.7		0.7
Fair value of financial liabilities held for trading at 31 March	(2.7	)	(1.1	)

In the UK and US a limited amount of proprietary trading within the limits and guidelines of the risk management framework is undertaken.

(j)  Currency exposures

As explained in the Financial Review on pages 30 to 43 the group uses forward contracts and cross currency interest rate swaps to mitigate the currency exposures arising from its net investment overseas. Gains and losses arising on net investment overseas and the forward contracts and cross currency interest rate swaps used to hedge the currency exposures, are recognised in the statement of total recognised gains and losses.

The group did not hold material net monetary assets or liabilities in currencies other than local currency at 31 March 2002 and 31 March 2001.

22  Other creditors

	2002 £m	2001 £m
Amounts falling due within one year:
Trade creditors	172.0	214.5
Corporate tax	293.3	365.0
Other taxes and social security	56.9	45.5
Payments received on account	29.3	28.7
Capital creditors and accruals	135.4	234.1
Other creditors	395.6	387.3
Accrued expenses	743.3	981.4
Proposed dividend	126.1	119.4
	1,951.9	2,375.9

85

NOTES TO THE GROUP BALANCE SHEET

as at 31 March 2002 continued

23  Provisions for liabilities and charges—Other provisions

1999/00	At 1 April 1999 £m	Acquisition £m	New provisions £m	Unwinding of discount £m	Utilised during year £m		Exchange £m	At 31 March 2000 £m
Reorganisation and restructuring	0.7	—	55.0	—	(11.7	)	—	44.0
Environmental and health	10.1	74.7	—	1.6	(2.9	)	0.5	84.0
Decommissioning costs	—	83.5	6.3	1.6	(0.5	)	0.6	91.5
Onerous contracts	—	—	79.0	—	—		—	79.0
Pensions and post-retirement benefits	8.8	102.8	13.4	—	(28.1	)	0.7	97.6
Mine reclamation costs	—	108.2	—	2.2	(6.3	)	0.7	104.8
Other	11.2	14.5	3.5	—	(8.8	)	0.1	20.5
	30.8	383.7	157.2	5.4	(58.3	)	2.6	521.4

2000/01	At 1 April 2000 £m	Acquisition/ revision to provisional fair values £m		Disposal £m		New provisions £m	Unwinding of discount £m	Utilised during year £m		Exchange £m	At 31 March 2001 £m
Reorganisation and restructuring	44.0	—		—		54.7	—	(17.8	)	4.2	85.1
Environmental and health	84.0	—		—		3.7	2.3	(2.4	)	9.2	96.8
Decommissioning costs	91.5	(15.2	)	(6.7	)	—	3.9	(0.8	)	9.4	82.1
Onerous contracts	79.0	171.5		—		—	6.3	(12.7	)	—	244.1
Pensions and post-retirement benefits	97.6	—		—		98.6	—	(47.6	)	16.3	164.9
Mine reclamation costs	104.8	—		(17.3	)	—	3.5	(11.8	)	11.1	90.3
Other	20.5			—		6.9	—	(13.3	)	1.3	15.4
	521.4	156.3		(24.0	)	163.9	16.0	(106.4	)	51.5	778.7

2001/02	Notes		At 1 April 2001 £m	Demerger of Thus (Note 33) £m		New provisions £m	Unwinding of discount £m	Utilised during year £m		Exchange £m		At 31 March 2002 £m
Reorganisation and restructuring	(a	)	85.1	—		18.5	—	(40.8	)	(0.2	)	62.6
Environmental and health	(b	)	96.8	—		0.1	5.7	(4.4	)	—		98.2
Decommissioning costs	(c	)	82.1	—		—	4.8	(0.3	)	—		86.6
Onerous contracts	(d	)	244.1	—		—	8.5	(67.3	)	—		185.3
Pensions and post-retirement benefits	(e	)	164.9	—		17.3	—	(19.3	)	(0.2	)	162.7
Mine reclamation costs	(f	)	90.3	—		—	3.8	(9.1	)	(0.1	)	84.9
Disposal of and withdrawal from Appliance Retailing	(g	)	—	—		50.8	—	(43.5	)	—		7.3
Other	(h	)	15.4	(0.9	)	22.6	—	(10.9	)	—		26.2
			778.7	(0.9	)	109.3	22.8	(195.6	)	(0.5	)	713.8

(a) The provisions for reorganisation and restructuring comprise certain costs relating to the PacifiCorp Transition Plan announced in May 2000, the estimated costs of restructuring the group’s UK businesses following the regulatory price reviews in the United Kingdom electricity and water industries announced in November 1999 and reorganisation provisions established in 2001/02 for the UK Division—Generation, Trading and Supply. The provisions are principally in respect of severance costs, most of which are expected to be incurred in the period up to March 2004. The PacifiCorp Transition Plan, upon completion, will result in a reduction in employee numbers of approximately 1,600 from the 1998 levels. At 31 March 2002, PacifiCorp had reduced its employees by approximately 750 under this Plan. The reorganisation provisions established in 2001/02 for the UK Division — Generation, Trading and Supply will result in a reduction in employee numbers of approximately 500 from 2002/03 onwards.

(b) The environmental and health provisions principally comprise the costs of notified environmental remediation work and constructive obligations in respect of potential environmental remediation costs identified by an external due diligence review in the United States. These costs are expected to be incurred in the period up to March 2010.

(c) The provision for decommissioning costs is the discounted future estimated costs of decommissioning the group’s power plants, principally in the United States, but also in the United Kingdom. The decommissioning of these plants is expected to occur over the period between 2005 and 2047.

(d) The provision for onerous contracts comprises the costs of contracted energy purchases. The costs provided are expected to be incurred in the period up to 31 March 2009 as follows: less than 1 year £26.6 million, between 1 and 2 years £35.3 million, between 2 and 5 years £86.6 million, and the remainder after 5 years £36.8 million.

(e) Details of the group’s pensions and other post-retirement benefits are disclosed in Notes 29 and 34.

(f) The provision for mine reclamation costs comprises the discounted future estimated costs of reclaiming the group’s mines in the United States. The costs are expected to be incurred in the period up to 2031.

(g) The Appliance Retailing provision comprises closure costs, principally property lease termination premia, expected to be incurred in the period up to 2004.

(h) The Other category comprises various provisions which are not individually sufficiently material to warrant separate disclosure.

86

24    Provisions for liabilities and charges—Deferred tax

Deferred tax provided in the Accounts is as follows:

	Provided
	2002 £m		2001 £m
Accelerated capital allowances	1,978.5		1,963.1
Other timing differences	(287.3	)	(337.8	)
	1,691.2		1,625.3

	£m
Deferred tax provided at 1 April 1999	743.1
Charge to profit and loss account	45.2
Movements arising from acquisition	818.1
Exchange	5.7
Deferred tax provided at 1 April 2000	1,612.1
Charge to profit and loss account	13.8
Movements arising from revisions to fair values	(98.5	)
Exchange	97.9
Deferred tax provided at 1 April 2001	1,625.3
Charge to profit and loss account	70.2
Other movements	(4.3	)
Deferred tax provided at 31 March 2002	1,691.2

25    Deferred income

	At 1 April 2000 £m	Receivable during year £m	Released to profit and loss account £m		Exchange £m	At 31 March 2001 £m
Grants and customer contributions	426.8	88.6	(15.1	)	1.2	501.5

	At 1 April 2001 £m	Receivable during year £m	Released to profit and loss account £m		Disposal £m		Exchange £m		At 31 March 2002 £m
Grants and customer contributions	501.5	67.7	(17.8	)	(0.1	)	(0.1	)	551.2

Deferred income excludes grants and contributions received in respect of water infrastructure assets.

26    Share capital

	Note	2002 £m	2001 £m
Authorised:
3,000,000,000 (2001 3,000,000,000) ordinary shares of 50p each		1,500.0	1,500.0
One Special Share of £1	(a)	—	—
		1,500.0	1,500.0
Allotted, called up and fully paid:
1,852,646,984 (2001 1,849,025,792) ordinary shares of 50p each		926.3	924.5
One Special Share of £1	(a)	—	—
		926.3	924.5

87

NOTES TO THE GROUP BALANCE SHEET

as at 31 March 2002—continued

(a)  Special Share

The ‘Special Share’, which can be held only by one of the Secretaries of State or any other person acting on behalf of HM Government, does not carry rights to vote at the general or separate meetings but entitles the holder to attend and speak at such meetings. Written consent of the Special Shareholder is required before certain provisions of the company’s Articles of Association or certain rights attaching to the Special Share are varied. This share shall confer no rights to participate in the capital or profits of the company, except that in a winding up the Special Shareholder shall be entitled to repayment in priority to the other shareholders. The Special Share is redeemable at par at any time by the Special Shareholder after consultation with the company.

(b)  Employee Share Plans

The group has six types of share based plans for employees. Options have been granted and awards made to eligible employees to subscribe for ordinary shares or ADSs in Scottish Power plc in accordance with the rules of each plan. The ScottishPower and Southern Water Sharesave Schemes are savings related and under normal circumstances share options are exercisable on completion of a three, five or seven year save-as-you-earn contract as appropriate.

The PacifiCorp Stock Incentive Plan relates to options over ScottishPower ADSs and vest over two or three years, as appropriate. The Executive Share Option Scheme applied to executive directors and certain senior managers. However, this Scheme was replaced with the Long Term Incentive Plan and, although it will not affect options already granted, this plan supersedes the Executive Share Option Scheme. Awards granted under the Long Term Incentive Plan will vest only if the Remuneration Committee is satisfied that certain performance measures related to the sustained underlying financial performance of the group and improvements in customer service standards are achieved over a period of three financial years commencing with the financial year preceding the date an award is made. During the year, the company introduced the Executive Share Option Plan 2001 (“ExSOP”). Options granted under the ExSOP to executive directors and certain senior managers are subject to the performance criterion that the percentage increase in the company’s annualised earnings per share be at least 3% (adjusted for any increase in the RPI).

The Employee Share Ownership Plan (“ESOP”) allows eligible employees to make contributions from pre-tax salary to buy shares in ScottishPower which are held in trust (Partnership Shares). These shares are matched by the company (Matching Shares) which are also held in trust. At the launch of the ESOP, Free Shares were offered to employees.

The K Plus Plan consists of the K Plus Employee Savings Plan and the K Plus Employee Stock Ownership Plan. The K Plus Employee Savings Plan is a 401(k) based qualified retirement plan designed to provide income during employees’ retirement. The K Plus Employee Stock Ownership Plan provides for matching contributions by PacifiCorp based on employees’ contributions, plus additional discretionary employer contributions made to all eligible employees.

(i)  Summary of movements in share options in ScottishPower shares

	ScottishPower Sharesave Schemes (number of shares 000s)		Weighted average exercise price (pence)	Southern Water Sharesave Scheme (number of shares 000s)		Weighted average exercise price (pence)	Executive Share Option Schemes # (number of shares 000s)		Weighted average exercise price (pence)	PacifiCorp Stock Incentive Plan ## (number of shares 000s)		Weighted average exercise price (pence)	Total (number of shares 000s)
Outstanding     at 1 April     1999	21,272		308.4	2,700		138.5	432		314.4	—		—	24,404
Acquisition*	—		—	—		—	—		—	14,534		562.1	14,534
Granted	4,745		429.0	—		—	—		—	6,016		460.2	10,761
Exercised	(3,674	)	272.6	(1,529	)	131.9	(168	)	344.6	—		—	(5,371	)
Lapsed	(2,398	)	345.7	(93	)	148.5	(1	)	352.1	(1,477	)	578.1	(3,969	)
Outstanding     at 1 April     2000	19,945		339.2	1,078		147.1	263		297.0	19,073		528.5	40,359
Granted	2,459		453.0	—		—	—		—	457		440.6	2,916
Exercised	(3,615	)	299.0	(786	)	145.7	(122	)	274.6	(304	)	528.2	(4,827	)
Lapsed	(2,577	)	400.7	(13	)	159.9	(1	)	—	(4,318	)	596.0	(6,909	)
Outstanding     at 1 April     2001	16,212		355.6	279		149.3	140		316.1	14,908		588.8	31,539
Granted	4,378		386.0	—		—	2,354		483.0	3,299		452.1	10,031
Exercised	(6,718	)	283.3	(189	)	144.7	(78	)	278.4	(99	)	474.3	(7,084	)
Lapsed	(2,115	)	420.6	(7	)	154.9	(19	)	483.0	(2,240	)	576.4	(4,381	)
Outstanding     at 31 March     2002	11,757		396.7	83		159.1	2,397		479.9	15,868		563.6	30,105

* PacifiCorp share options as at 29 November 1999.

# The Executive Share Option figures shown for 2001/02 are a combination of the options outstanding under the Executive Share Option Scheme and the Executive Share Option Plan 2001.

## PacifiCorp Stock Incentive Plan are options over ScottishPower ADSs; for the purpose of the table above, options have been converted to ScottishPower shares as follows: one ScottishPower ADS equals four ScottishPower shares.

88

(ii)  Analysis of share options outstanding at 31 March 2002

	Date of grant	Number of participants	Number of shares (000s)	Option price (pence)	Normal exercisable date
ScottishPower Sharesave Schemes	20 June 1996	5	7	263.1	6 months to March 2002
	20 June 1997	1,697	2,130	307.0	6 months to March 2003
	12 June 1998	1,743	1,578	440.0	6 months to March 2002 or 2004
	11 June 1999	3,465	2,592	429.0	6 months to March 2003 or 2005
	9 June 2000	2,440	1,459	453.0	6 months to March 2004 or 2006
	8 June 2001	3,492	3,991	386.0	6 months to March 2005 or 2007
Southern Water Sharesave Scheme	25 January 1995	3	4	136.1	6 months to September 2002
	26 January 1996	49	79	160.2	6 months to September 2003
Executive Share Option Scheme	25 June 1992	3	2	237.7	1995-2002
	1 July 1993	1	13	310.0	1996-2003
	17 December 1993	14	20	454.8	1996-2003
	27 May 1994	1	1	354.0	1997-2004
	12 May 1995	3	26	335.0	1998-2005
Executive Share Option Plan 2001	21 August 2001	269	2,335	483.0	21 August 2004 to 21 August 2011
PacifiCorp Stock Incentive Plan**	3 June 1997	67	1,262	599.6	29 November 1999 to 3 June 2007
	12 August 1997	18	177	645.1	29 November 1999 to 12 August 2007
	10 February 1998	94	2,231	728.5	29 November 1999 to 10 February 2008
	13 May 1998	5,104	1,178	704.0	29 November 1999 to 13 May 2008
	9 February 1999	102	2,910	576.8	9 February 2000 to 9 February 2009##
	11 May 1999	5,391	1,242	521.8	11 May 2000 to 11 May 2009***
	16 February 2000	101	2,143	474.3	16 February 2001 to 16 February 2010###
	24 March 2000	4	1,343	559.0	24 March 2001 to 24 March 2010
	25 January 2001	2	457	441.3	25 January 2002 to 25 January 2011####
	24 April 2001	108	2,717	452.5	24 April 2002 to 24 April 2011
	11 September 2001	1	208	448.1	11 September 2002 to 11 September 2011

** Options granted under the PacifiCorp Stock Incentive Plan are for ScottishPower ADSs; for the purpose of the table above, options have been converted to ScottishPower ordinary shares as follows: one ScottishPower ADS equals four ScottishPower ordinary shares. The US$ ADS option price was converted so that it may be represented in terms of ScottishPower ordinary shares. The price was further converted at the closing exchange rate on 31 March 2002 to be quoted in pence in the table above.

## Options became exercisable in the proportions of one-third on 9 February 2000, one-third on 9 February 2001 and the remaining one-third on 9 February 2002.

*** Options became exercisable in the proportions 50% on 11 May 2000 and the remaining 50% on 11 May 2001.

### Options became exercisable in the proportions of one-third on 16 February 2001, one-third on 16 February 2002 and the remaining one-third becomes exercisable on 16 February 2003.

#### Options became exercisable in the proportions of one-third on 25 January 2002, with a further third becoming exercisable on 25 January 2003 and the remaining one-third becomes exercisable on 25 January 2004.

Where reference is made to Southern Water, this is to identify the Sharesave Scheme under which the options over Scottish Power plc ordinary shares have been granted. The exercise prices of options granted prior to the rights issue on 30 August 1996 were adjusted to reflect the bonus element inherent in the rights issue.

For the Southern Water Sharesave Scheme, the date of grant refers to the date the original Southern Water Sharesave Scheme share options were granted. These options were exchanged for options over ScottishPower shares following acquisition in 1996.

Where reference is made to the PacifiCorp Stock Incentive Plan, this is to identify the scheme under which the options over Scottish Power plc ADSs have been granted. For the PacifiCorp Stock Incentive Plan, the date of grant refers to the date the original PacifiCorp Common Stock options were granted. These options were exchanged for options over ScottishPower ADSs following the acquisition on 29 November 1999.

89

NOTES TO THE GROUP BALANCE SHEET

as at 31 March 2002—continued

27    Analysis of movements in shareholders’ funds

	Notes		Number of shares 000s		Share capital €m		Share premium €m		Revaluation reserve €m		Capital redemption reserve €m		Merger reserve €m	Other reserve €m		Profit and loss account €m		Total €m
At 1 April 1999			1,198,678		599.4		—		223.9		—		394.0	—		(14.5	)	1,202.8
Retained profit for the year			—		—		—		—		—		—	—		543.6		543.6
Share capital issued
—Employee sharesave scheme			12,044		6.0		49.7		—		—		—	(1.5	)	(16.2	)	38.0
—Executive share option scheme			168		0.1		0.5		—		—		—	—		—		0.6
—Acquisition			689,669		344.8		3,687.8		—		—		—	—		—		4,032.6
Revaluation surplus realised			—		—		—		(3.4	)	—		—	—		3.4		—
Impairment of goodwill previously written off to reserves			—		—		—		—		—		—	—		7.5		7.5
Goodwill realised on disposals			—		—		—		—		—		—	—		15.3		15.3
Share buy-back			(52,973	)	(26.5	)	—		—		26.5		—	—		(302.0	)	(302.0	)
Exchange movement on translation of overseas results and net assets	(b	)	—		—		—		—		—		—	—		24.9		24.9
Transfers			—		—		(4.2	)	—		(8.2	)	12.4	1.5		(1.5	)	—
At 1 April 2000			1,847,586		923.8		3,733.8		220.5		18.3		406.4	—		260.5		5,563.3
Retained loss for the year			—		—		—		—		—		—	—		(169.8	)	(169.8	)
Share capital issued
—Employee sharesave scheme			304		0.1		1.4		—		—		—	—		—		1.5
—Executive share option scheme			122		0.1		0.1		—		—		—	—		—		0.2
—ESOP			1,014		0.5		4.4		—		—		—	—		—		4.9
Revaluation surplus realised			—		—		—		(3.4	)	—		—	—		3.4		—
Exchange movement on translation of —overseas
results and net assets	(b	)	—		—		—		—		—		—	—		493.1		493.1
At 1 April 2001			1,849,026		924.5		3,739.7		217.1		18.3		406.4	—		587.2		5,893.2
Retained loss for the year			—		—		—		—		—		—	—		(1,927.2	)	(1,927.2	)
Share capital issued
—Employee sharesave scheme			99		0.1		0.5		—		—		—	—		—		0.6
—Executive share option scheme			78		—		0.2		—		—		—	—		—		0.2
—ESOP			3,444		1.7		13.7		—		—		—	—		—		15.4
Goodwill realised on disposals	(c	)	—		—		—		—		—		—	—		753.3		753.3
Goodwill realised on demerger of Thus	33		—		—		—		—		—		—	—		14.7		14.7
Reduction of share premium	(d	)	—		—		(1,500.0	)	—		—		—	—		1,500.0		—
Unrealised gains on fixed asset disposals			—		—		—		—		—		—	4.9		—		4.9
Gains realised on Thus demerger			—		—		—		—		—		—	(4.9	)	4.9		—
Revaluation surplus realised			—		—		—		(3.4	)	—		—	—		3.4		—
Fixed asset revaluation gains realised on disposal			—		—		—		(168.2	)	—		—	—		168.2		—
Exchange movement on translation of overseas results and net assets	(b	)	—		—		—		—		—		—	—		(4.2	)	(4.2	)
Currency translation differences on foreign currency hedging	(b	)	—		—		—		—		—		—	—		(19.5	)	(19.5	)
Balance at 31 March 2002			1,852,647		926.3		2,254.1		45.5		18.3		406.4	—		1,080.8		4,731.4

(a) Cumulative goodwill written off to the profit and loss account reserve as at 31 March 2002 was £572.3 million (2001 £1,349.9 million, 2000 £1,349.9 million).

(b) The cumulative foreign currency translation adjustments at 31 March 2002 amount to £494.3 million (2001 £518.0 million, 2000 £24.9 million).

(c) The goodwill realised on disposals relates to the disposal of Appliance Retailing (£15.1 million) and the impairment of goodwill in connection with the provision for loss on disposal of Southern Water (£738.2 million).

(d) The company applied to the Court of Session (‘the Court’) to approve a reduction in the share premium account which had previously been approved by the company’s shareholders at an Extraordinary General Meeting on 21 January 2002. On 5 March 2002, the Court approved the reduction of the company’s share premium account by £1,500 million. This amount has been transferred to the company’s profit and loss account reserve. The reduction in the share premium account created sufficient distributable reserves to facilitate payment of a dividend in specie to demerge Thus.

(e) When ScottishPower acquired Southern Water plc, a balance was established under merger reserve for the cost to ScottishPower of transferring existing options over Southern Water plc shares to the Scottish Power plc Share Option Scheme. Prior to 1 April 2000, transfers were made between the Other reserve and the Profit and loss account reserve to reflect the exercise of these options as new shares were issued. However, the shares to satisfy the exercise of these options have now been acquired by a Qualifying Employee Share Ownership Trust and, accordingly, no further such transfers between reserves are required.

82

28    Minority interests

	Note	Equity 2002 £m		Non-equity 2002 £m		Total 2002 £m		Equity 2001 £m		Non-equity 2001 £m		Total 2001 £m
At 1 April		128.2		157.6		285.8		161.6		138.1		299.7
Exchange		—		(1.7	)	(1.7	)	—		19.5		19.5
Additions		1.0		—		1.0		—		—		—
Disposals		2.2		—		2.2		—		—		—
Thus open offer		34.4		—		34.4		—		—		—
Demerger of Thus	33	(127.4	)	—		(127.4	)	—		—		—
Redemption of preferred stock of PacifiCorp		—		(69.5	)	(69.5	)	—		—		—
Profit and loss account		(41.8	)	6.9		(34.9	)	(33.4	)	10.4		(23.0	)
Unrealised gains on fixed asset disposals		4.9		—		4.9		—		—		—
Dividends paid to minority interests		—		(8.1	)	(8.1	)	—		(10.4	)	(10.4	)
At 31 March		1.5		85.2		86.7		128.2		157.6		285.8

Non-equity minority interests include 100% of the preferred stock and preferred stock subject to mandatory redemption of PacifiCorp. Of the total preferred stock subject to mandatory redemption at 31 March 2002, £2.6 million (2001 £75.7 million) is due to be redeemed within 1 year, £2.6 million (2001 £2.6 million) is due to be redeemed in each of the next 4 years with the remaining £39.2 million (2001 £42.4 million) being redeemable after 5 years.

The fair value of preferred stock subject to mandatory redemption is £57.4 million (2001 £130.5 million). The fair value of other preferred stock is not materially different from book value.

The weighted average rate of return on preferred stock subject to mandatory redemption is 7.6% (2001 7.6%) and on other preferred stock is 5.1% (2001 5.1%). Preferred stockholders have first preference in the event of a liquidation of PacifiCorp and first rights to dividends. The holders of these shares only have rights against the PacifiCorp group of companies.

29    Pensions

At 31 March 2002, ScottishPower had eight statutorily approved defined benefit pension schemes and one statutorily approved defined contribution scheme. The pension charge for the PacifiCorp arrangements in the year to 31 March 2000 is for the post-acquisition period only. Details of the principal schemes are set out below:

Pension fund	Scheme type	Funded or unfunded	Pension charge for the year						Prepayment/ (provision) as at 31 March
			2002 £m		2001 £m		2000 £m		2002 £m		2001 £m
ScottishPower	Defined benefit	funded	—		—		—		5.0		5.0
Manweb	Defined benefit	funded	3.6		4.3		4.2		—		—
Southern Water	Defined benefit	funded	4.1		3.7		4.1		—		—
Final Salary LifePlan	Defined benefit	funded	3.4		3.0		1.0		—		—
PacifiCorp*	Defined benefit	funded	7.5	**	63.7	***	5.3	****	(88.4	)	(85.9	)

* The PacifiCorp figures include the unfunded Supplementary Executive Retirement Plan (“SERP”). The SERP accounts for less than 5% of the PacifiCorp liabilities.

** Includes £0.6 million charge in the year relating to Special Termination Benefits.

*** Includes £54.8 million charge in the year relating to Special Termination Benefits.

**** In relation to the post-acquisition period only.

The components of the pension charge are as follows:

		2002						2001
Pension fund	Regular cost £m	Interest (credit)/ cost on prepayment/ provision £m		Variation credit £m		Net pension charge £m	Regular cost £m	Interest (credit)/ cost on prepayment/ provision £m		Variation credit £m		Net pension charge £m
ScottishPower*	21.8	(0.3	)	(32.5	)	—	26.5	(0.3	)	(39.5	)	—
Manweb	5.1	—		(1.5	)	3.6	5.8	—		(1.5	)	4.3
Southern Water	4.8	—		(0.7	)	4.1	4.7	—		(1.0	)	3.7
Final Salary LifePlan	3.4	—		—		3.4	3.0	—		—		3.0
PacifiCorp	10.4	6.7		(9.6	)**	7.5	12.6	5.8		45.3	***	63.7

* The net pension charge is set to a minimum of nil where the variation credit exceeds regular cost plus interest.

** Being a normal variation credit of £10.2 million decreased by the cost of Special Termination Benefits of £0.6 million.

*** Being a normal variation credit of £9.5 million increased by the cost of Special Termination Benefits of £54.8 million.

The prepayment/(provision) as at the year end can be reconciled as follows:

Pension fund	Prepayment/ (provision) at 1 April 2001 £m		Employer contribution £m	Pension charge £m		Exchange £m		Prepayment/ (provision) at 31 March 2002 £m		Prepayment/ (provision) at 1 April 2000 £m		Employer contribution £m	Pension charge £m		Exchange £m		Prepayment/ (provision) at 31 March 2001 £m
ScottishPower	5.0		–	–		–		5.0		5.0		–	–		–		5.0
Manweb	–		3.6	(3.6	)	–		–		–		4.3	(4.3	)	–		–
Southern Water	–		4.1	(4.1	)	–		–		–		3.7	(3.7	)	–		–
Final Salary LifePlan	–		3.4	(3.4	)	–		–		–		3.0	(3.0	)	–		–
PacifiCorp	(85.9	)	5.1	(7.5	)	(0.1	)	(88.4	)	(32.6	)	16.6	(63.7	)	(6.2	)	(85.9	)

91

NOTES TO THE GROUP BALANCE SHEET

as at 31 March 2002—continued

The individual scheme funding details based on the latest full actuarial valuations are as follows:

						Principal actuarial assumptions
Pension fund	Latest full actuarial valuation	Valuation carried out by	Value of assets based on valuation £m	Market value of assets £m	Valuation method adoption	Average investment rate of return		Average salary increases		Average pension increases		Value of fund assets/ accrued benefits
ScottishPower	31 March 2000	William M Mercer	1,930.4	2,090.4	Projected unit	6.0	%	4.5	%	2.5	%	129	%
Manweb	31 March 2001	Bacon & Woodrow	640.8	623.6	Projected unit	6.8	%*	4.3	%	2.5	%	111	%
Southern Water	31 March 2001	Watson Wyatt	296.0	296.0	Projected unit	6.2	%	4.5	%	2.5	%	107	%
Final Salary LifePlan	31 March 1999	William M Mercer	0.1	0.1	Projected unit	5.5	%	4.0	%	2.5	%	97	%
PacifiCorp	1 January 2001	Hewitt Associates	760.6	760.6	Projected unit	7.75	%**	4.0	%	—		100	%

* 4.8% post-retiral

** 7.75% represents the liability discount rate.

(a)  Group pension arrangements

Following a review of the group’s UK pension arrangements, the ScottishPower Pension Scheme, Manweb Pension Scheme and Southern Water Pension Scheme were closed to new members from 31 December 1998.

The group introduced two new group pension plans for new UK employees effective from 1 January 1999. The new plans are a defined benefit plan (Final Salary LifePlan) and a defined contribution plan (Money Purchase LifePlan) which are open to continuous contract employees aged between 16 and 60.

Following the acquisition of PacifiCorp on 29 November 1999, the associated US pension arrangements are now included in the group’s Accounts. Further details of these US arrangements are given in sub-note (f) below.

Each of the pension schemes’ assets are invested in an appropriate diversified range of equities, bonds, property and cash. The broad proportions invested in each asset class at 31 March 2002 are as follows:

	Equities %	Bonds %	Property %	Cash %	Total %
ScottishPower	72	18	9	1	100
Manweb	70	29	—	1	100
Southern Water	74	24	—	2	100
Final Salary LifePlan	94	—	—	6	100
PacifiCorp	65	35	—	—	100

(b)  ScottishPower

Scottish Power UK plc operates a funded pension scheme of the company providing defined retirement and death benefits based on final pensionable salary. This scheme was open prior to 1 January 1999 to employees of ScottishPower. Members are required to contribute to the Scheme at a rate of 5% of pensionable salary. Scottish Power UK plc meets the balance of cost of providing benefits, and company contributions paid are based on the results of the actuarial valuation of the Scheme and are agreed by Scottish Power UK plc and the Scheme Trustees.

The assets of the Scheme are held separately from those of the company in a trustee administered fund. Included in the Scheme assets are 133,602 ScottishPower shares based on market value as at 31 March 2002), purchased only as part of a pooled strategy to match the relative weightings in the UK Stock Exchange index.

The pension charge for the year is based on the advice of the Scheme’s independent qualified actuary and is calculated using the same assumptions as those used at the last actuarial valuation of the Scheme. The Scheme assets have been taken at an adjusted market value.

The prepayment included in the balance sheet represents the accumulated excess of the actual contributions paid to the Scheme over the pension accounting charge. The net pension charge is set to a minimum of which is derived from a regular cost of 19.8% of salaries, fully offset by a variation credit. The variation credit is calculated as the assessed surplus, less the prepayment, spread as a fixed percentage of pensionable salary roll over nine years.

The actual contributions payable by participating employers during the year were £nil, except where required by a business transfer agreement. There are no planned changes to employer contribution requirements.

(c)  Manweb

Prior to 1 January 1999, most of the Manweb employees were entitled to join the Manweb Group of the Electricity Supply Pension Scheme, which provides pension and other related benefits based on final pensionable salary to employees throughout the Electricity Supply Industry in England & Wales. The ongoing contributions to the Scheme are based on the results of the actuarial valuation of the Scheme and the advice of the Scheme Actuary.

The assets are held in a separate trustee administered fund. The Scheme assets no longer include any ScottishPower shares. For funding and expensing purposes the Scheme assets are valued by discounting the income which can be expected from a national portfolio of assets at the valuation rate of interest.

92

The most recent formal funding valuation was carried out as at 31 March 2001. However, the results and recommendations of this valuation were not completed and implemented until 1 April 2002. Consequently the actual funding amounts payable and the corresponding expensing amounts for the year ended 31 March 2002 have been calculated using the assumptions of the 1998 actuarial valuation of the scheme. The 1998 assumptions are detailed as follows:

1998 valuation assumptions
Value of plan assets	£	467.6m
Market value of assets	£	613.7m
Valuation method adopted		Projected unit
Average investment rate of return		8.5	%
Average salary increases		6.5	%
Average pension increases		4.5	%
Average equity dividend growth		4.75	%
Value of fund assets/accrued benefits		105	%

The pension charge for the year, of 12% of pensionable salaries, is based on the advice of the Scheme’s independent qualified actuary and is calculated using the 1998 assumptions detailed above. Based on the results of the 2001 valuation, the pension charge in respect of future benefits accruing is 14% of pensionable salary. However, due to the surplus revealed in the 2001 valuation, the company will take a contribution holiday which will continue until the results of the next actuarial valuation. The variation credit is calculated as a spreading of the combination of the assessed surplus and Early Retirement Deficiency Costs payable over 14 years.

The actual contributions payable by participating employers during the year were 12% of pensionable salaries adjusted as described above or as required by a business transfer agreement. The employer contribution rate changed with effect from 1 April 2002 to £nil (except as required by a business transfer agreement).

(d)  Southern Water

Southern Water operates a funded pension scheme. The Scheme details above relate to the principal defined benefit scheme which covers the majority of the Southern Water employees. Members are required to contribute to the Scheme at varying rates of pensionable salary depending upon category of membership. The company meets the balance of the cost of the accruing benefits. Contributions paid are based on the results of the actuarial valuation of the Scheme and are agreed by the company and the Scheme Trustees.

The assets are held in a separate trustee administered fund. For funding and expensing purposes, the scheme assets are valued by discounting the income which can be expected from a notional portfolio of assets at the valuation rate of interest.

The pension charge for the year, of 10% of pensionable salaries, plus employer augmentation costs, is based on the advice of the Scheme’s independent qualified actuary and is calculated using the same assumptions as at the last actuarial valuation of the Scheme. The variation credit is calculated as the assessed surplus spread over 17 years.

The actual contributions payable by participating employers during the year were 11.4% of pensionable salaries, except where required by a business transfer agreement. This rate continues with effect from 1 April 2002 following the formal actuarial valuation of the scheme as at 31 March 2001.

(e)  Final Salary LifePlan

The group operates a funded pension scheme providing defined retirement and death benefits based on final pensionable salary for eligible UK employees of the group. The assets of the LifePlan are held in a separate trustee administered fund. The pension charge for the year, of 11.4% of pensionable salaries, is based on the advice of the LifePlan’s independent qualified actuary, representing the assessed balance of cost of the accruing benefits after allowing for members’ contributions of 5% of pensionable salaries. The same actuarial assumptions have been adopted for both funding and expensing purposes.

The actual contributions payable by participating employers during the year were 10.0% of pensionable salaries, except where required by a business transfer agreement. There are no planned changes to employer contribution requirements, although this is subject to the results of the actuarial valuation as at 31 March 2002 when these become known.

(f)  PacifiCorp

        PacifiCorp operates pension plans covering substantially all its employees. Benefits are based on the employee’s years of service and final pensionable salary, adjusted to reflect estimated social security benefits. Pension costs are funded annually by no more than the maximum amount of pension expense which can be deducted for federal income tax purposes. The PacifiCorp pensions figures in these Accounts include the unfunded Supplementary Executive Retirement Plan (“SERP”). The SERP accounts for less than 5% of the PacifiCorp liabilities. PacifiCorp meets the entire cost of accruing benefits under PacifiCorp plans. The assets for the funded Plan are held in a separate fund. For funding and expensing purposes, the Plan assets are valued at market levels, and liabilities costed on financial assumptions in line with market return expectations. The pension charge for the period is based on the advice of the Plan’s independent qualified actuary. PacifiCorp also provides post-retirement benefits and post-employment benefits to certain employees. Details of these benefits are disclosed in Note 34.

The actual contributions payable by participating employers during the year were 1.8% of pensionable earnings. The planned contribution for 2002/03 is expected to increase to 8.9% of pensionable earnings.

(g)  Additional pension and other post-retirement benefit arrangements

The group operates an approved defined contribution pension scheme (Money Purchase LifePlan) for eligible employees. Contributions are paid by the member and employer at fixed rates. The benefits secured at retirement or death reflect each employee’s accumulated fund and the cost of purchasing benefits at that time. The assets of the scheme are held in a separate trustee administered fund. The pension charge for the year represents the defined employer contribution and amounted to £0.3 million. The group also operates pension schemes for a number of other groups of employees; details of these have been omitted from the Accounts on the grounds of materiality.

Further details of the group’s pensions arrangements are disclosed in Note 34, together with details of the group’s other post-retirement benefits for PacifiCorp employees.

93

NOTES TO THE GROUP BALANCE SHEET

as at 31 March 2002—continued

(h)  Financial Reporting Standard (“FRS”) 17 ‘Retirement benefits’

The pension figures shown above comply with the current pension accounting standard, Statement of Standard Accounting Practice (“SSAP”) 24. A new accounting standard, FRS 17, must be used for the pension and other post-retirement benefits figures that will be recorded in the group’s Accounts for the year ending 31 March 2004 and subsequent years. Under transitional arrangements the group is required to disclose the following information about the schemes and the figures that would have been shown under FRS 17 in the balance sheet as at 31 March 2002.

The major assumptions used by the actuary for both the pensions and other post-retirement benefits arrangements were:

	UK arrangements at 31 March 2002	US arrangements at 31 March 2002
Rate of increase in salaries	4.3% p.a.	4.0% p.a.
Rate of increase in deferred pensions	2.8% p.a.	n/a
Rate of increase in pensions in payment	2.8% p.a.	n/a
Discount rate	6.0% p.a.	7.5% p.a.
Inflation assumption	2.8% p.a.	4.0% p.a.

Pensions

The group operates defined benefit and defined contribution pension schemes as described earlier in this Note. Full actuarial valuations were carried out as described earlier and updated to 31 March 2002 by a qualified independent actuary. Figures are shown separately for the UK and US arrangements.

The assets in the schemes and the expected long-term rates of return were as follows:

	UK pension arrangements Value at 31 March 2002 £m		US pension arrangements Value at 31 March 2002 £m
Equities	1,881.4		375.1
Bonds	551.1		206.8
Property	159.3		—
Other	31.0		—
Total market value of assets	2,622.8		581.9
Present value of schemes’ past service liabilities	(2,352.1	)	(760.1	)
Excess/(deficit) of schemes’ assets over past service liabilitites	270.7		(178.2	)
Resulting balance sheet asset/(liability)	186.4	*	(178.2	)
Related deferred tax (liability)/asset	(55.9	)	67.7
Net pension asset/(liability)	130.5		(110.5	)

* The balance sheet asset which would have arisen under FRS 17 is lower than the total calculated excess of schemes’ assets over past service liabilities, due to part of the ScottishPower Pension Scheme’s past service ‘surplus’ being designated as “non-recoverable” in FRS 17 terms and therefore excluded from the balance sheet.

The UK pension arrangements net pension asset comprises assets (net of deferred tax) of £159.1 million and liabilities (net of deferred tax) of £28 .6 million.

	UK pension arrangements Long-term rates of return expected at 31 March 2002	US pension arrangements Long-term rates of return expected at 31 March 2002
Equities	8.0% p.a.	10.75% p.a.
Bonds	5.3% p.a.	6.5% p.a.
Property	7.0% p.a.	n/a

Other post-retirement benefits

PacifiCorp provides post-retirement healthcare and life insurance benefits as described in Note 34(e). Actuarial valuations were carried out as at 31 March 2002 by a qualified independent actuary. The major assumptions used by the actuary are described in Note 34(e).

The assets in the schemes and the expected long-term rates of return were as follows:

	Value at 31 March 2002 £m
Equities	117.6
Bonds	67.3
Total market value of assets	184.9
Present value of schemes’ liabilities	(331.3	)
Deficit in the schemes	(146.4	)
Related deferred tax asset	55.6
Net other post-retirement benefits liability	(90.8	)

	Long-term rates of return expected at 31 March 2002
Equities	10.75% p.a.
Bonds	6.5% p.a.

94

SUMMARY

If the above FRS 17 pensions and other post-retirement benefits assets and liabilities (net of deferred tax) were recognised in the balance sheet as at 31 March 2002, the group’s net assets and profit and loss reserve would be as follows:

	At 31 March 2002 £m
Net assets	4,818.1
Reversal of SSAP 24 net pensions/other post-retirement benefits liability (net of deferred tax)	97.4
Net assets excluding FRS 17 pensions/other post-retirement benefits assets and liabilities (net of deferred tax)	4,915.5
FRS 17 pensions assets (net of deferred tax)	159.1
FRS 17 pensions/other post-retirement benefits liabilities (net of deferred tax)	(229.9	)
Net assets including FRS 17 pensions/other post-retirement benefits assets and liabilities (net of deferred tax)	4,844.7
Profit and loss reserve	1,080.8
Reversal of SSAP 24 net pensions/other post-retirement benefits liability (net of deferred tax)	97.4
Profit and loss reserve excluding FRS 17 pensions/other post-retirement benefits assets and liabilities (net of deferred tax)	1,178.2
FRS 17 pensions/other post-retirement benefits assets and liabilities (net of deferred tax)	(70.8	)
Profit and loss reserve including FRS 17 pensions/other post-retirement benefits assets and liabilities (net of deferred tax)	1,107.4

30    Contingent liabilities

Thus Flotation

In November 1999, the group floated a minority stake in its internet and telecommunications business, Thus plc. This gave rise to a contingent liability to corporation tax on chargeable gains, estimated at amounts up to £570 million.

On 19 March 2002, the group demerged its residual holding in Thus Group plc (the new holding company of Thus plc). The charge referred to above could still arise, in certain circumstances, before 19 March 2007. Members of the ScottishPower group have agreed to indemnify Thus Group plc for any such liability, except in circumstances arising without the consent of the ScottishPower group.

Legal proceedings

The group’s businesses are parties to various legal claims, actions and complaints, certain of which involve material amounts. Although the group is unable to predict with certainty whether or not it will ultimately be successful in these legal proceedings or, if not, what the impact might be, the directors currently believe that disposition of these matters will not have a materially adverse effect on the group’s consolidated Accounts.

31    Financial commitments

(a)  Analysis of annual commitments under operating leases

	2002 £m	2001 £m
Leases of land and buildings expiring:
Within one year	0.2	0.6
Between one and two years	1.3	1.7
Between two and three years	0.1	0.6
Between three and four years	—	0.5
Between four and five years	1.8	0.8
More than five years	1.0	28.7
	4.4	32.9
Other operating leases expiring:
Within one year	3.9	5.5
Between one and two years	3.6	5.4
Between two and three years	2.5	5.2
Between three and four years	0.7	1.2
Between four and five years	0.9	0.8
More than five years	0.2	0.4
	11.8	18.5

(b)  Capital commitments

	2002 £m	2001 £m
Contracted but not provided	238.9	174.9

(c) Other contractual commitments

(i) Under contractual arrangements in the UK, the group has the following purchase commitments at 31 March 2002:

	2003 £m	2004 £m	2005 £m	2006 £m	2007 £m	Thereafter £m	Total £m
Commitments to purchase in year	789.7	696.3	684.1	270.1	263.1	1,292.2	3,995.5

(ii) In the US, PacifiCorp manages its energy resource requirements by integrating long-term firm, short-term and spot market purchases with its own generating resources to economically operate the system (within the boundaries of Federal Energy Regulatory Commission requirements) and meet commitments for wholesale sales and retail load growth. The long-term wholesale sales commitments include contracts with minimum sales requirements of  £237.6 million,  £219.5 million, £188.3 million, £161.2 million and £134.5 million for the years 2003 to 2007 respectively. As part of its energy resource portfolio, PacifiCorp acquires a portion of its power through long-term purchases and/or exchange agreements which require minimum fixed payments of £244.1 million, £234.6 million, £237.6 million, £235.3 million and £242.3 million for the years 2003 to 2007 respectively. The purchase contracts include agreements with the Bonneville Power Administration, the Hermiston Plant and a number of co-generating facilities.

Excluded from the minimum fixed annual payments above are commitments to purchase power from several hydro-electric projects under long-term arrangements with public utility districts. These purchases are made on a ‘cost-of-service’ basis for a stated percentage of project output and for a like percentage of project annual costs (operating expenses and debt service). PacifiCorp is required to pay its portion of operating expenses and its portion of the debt service, whether or not any

95

NOTES TO THE GROUP BALANCE SHEET

as at 31 March 2002—continued

power is produced.

The arrangements provide for non-withdrawable power and the majority also provide for additional power, withdrawable by the public utility districts upon one to five years’ notice. For 2002, these purchases represented approximately 1.9% of PacifiCorp’s energy requirements. At 31 March 2002, PacifiCorp’s share of long-term arrangements with public utility districts were as follows:

Generating Facility	Year contract expires	Percentage of output		Capacity (kw)	Annual costs* £m
Wanapum	2009	18.9	%	155,444	4.9
Priest Rapids	2005	13.9	%	109,602	2.8
Rocky Reach	2011	5.3	%	64,297	2.2
Wells	2018	6.9	%	59,617	1.4
Total				388,960	11.3

* The annual costs include debt service costs of  £4.4 million. PacifiCorp’s minimum debt service obligation at 31 March 2002 was  £6.3 million,  £6.3 million,  £5.6 million,  £7.0 million and  £7.0 million for the years 2003 to 2007, respectively.

(iii)  Short-term wholesale sales and purchased power contracts

At 31 March 2002, PacifiCorp had short-term wholesale forward sales commitments that included contracts with minimum sales requirements of  £107.6 million for 2003. At 31 March 2002, short-term forward purchase agreements require minimum fixed payments of  £162.4 million for 2003.

(iv)  Fuel contracts

PacifiCorp has ‘take or pay’ coal and natural gas contracts that require minimum fixed payments of  £113.1 million,  £109.8 million,  £103.0 million,  £92.3 million and  £81.0 million for the years 2003 to 2007 respectively.

(v)  At 31 March 2002, PPM had purchase commitments of  £340.7 million of which  £227.8 million relates to the years 2003 to 2007.

32    Related party transactions

(a)  Trading transactions and balances arising in the normal course of business

				Sales/(purchases) to/(from) other group companies during the year				Amounts due from/(to) other group companies as at 31 March
Related Party	Related party relationship to group	2002 £m		2001 £m		2000 £m		2002 £m		2001 £m
Sales by related parties
Scottish Electricity Settlements Limited	50% owned joint venture	5.3		6.2		8.7		1.1		1.4
ScotAsh Limited	50% owned joint venture	0.6		0.4		0.2		0.2		0.4
South Coast Power Limited	50% owned joint venture	46.5		25.1		—		3.0		3.5
CeltPower Limited	50% owned joint venture	1.7		1.7		1.8		0.3		0.1
Calanais Limited*	50% owned joint venture	—		69.0		—		—		0.6
Thus**	Subsidiary	0.9		—		—		12.0		—
Purchases by related parties
Scottish Electricity Settlements Limited	50% owned joint venture	(0.2	)	(0.2	)	(0.4	)	—		—
ScotAsh Limited	50% owned joi000nt venture	(0.2	)	(0.2	)	(0.3	)	—		(0.2	)
South Coast Power Limited	50% owned joint venture	(7.8	)	(3.2	)	(0.3	)	(0.5	)	(0.6	)
Klamath co-generation plant	Joint arrangement	(24.1	)	—		—		(2.2	)	—
CeltPower Limited	50% owned joint venture	(0.3	)	(0.3	)	(0.4	)	—		—
Calanais Limited*	50% owned joint venture	—		(13.0	)	—		—		(0.8	)
Thus**	Subsidiary	(0.1	)	—		—		(5.2	)	—
N.E.S.T. Makers Limited	50% owned joint venture	(0.3	)	—		—		—		—

* On 23 March 2001 the group disposed of its 50% holding in Calanais Limited; as a result it ceased to be a joint venture from this date.

In addition to the above, during the year ended 31 March 2002, PacifiCorp made management and similar charges to Powercor of £nil as a result of the disposal of Powercor by PacifiCorp in September 2000 (31 March 2001 £1.4 million, 30 November 1999 to 31 March 2000 £2.0 million). At 31 March 2002, Powercor owed the group (2001 £nil, 2000 £21.9 million).

During the year ended 31 March 2002, ScottishPower made management and similar charges to ScotAsh Limited of £0.4 million (2001 £0.2 million, 2000 £0.1 million).

96

(b)  Funding transactions and balances arising in the normal course of business

				Interest payable to other group companies during the year				Amounts due to other group companies as at 31 March
Related party	Related party relationship to group	Note		2002 £m		2001 £m		2002 £m		2001 £m
Scottish Electricity Settlements Limited	50% owned joint venture			(1.1	)	(1.4	)	(14.7	)	(16.6	)
ScotAsh Limited	50% owned joint venture			—		—		(2.4	)	(3.0	)
South Coast Power Limited	50% owned joint venture			(1.1	)	—		(13.5	)	—
RoboScot (38) Limited	50% owned joint venture			—		—		(5.4	)	(5.4	)
Thus**	Subsidiary	(i	)	—		—		(5.4	)	—
N.E.S.T. Makers Limited	50% owned joint venture			—		—		(0.8	)	—

(i) This balance represents £1.1 million of loans and £4.3 million payable in respect of finance leases.

** On 19 March 2002 the group demerged Thus. The related party sales and purchases represent those transactions between ScottishPower and Thus for the period from 20 March to 31 March 2002.

33    Thus Group plc demerger

On 19 March 2002, the group demerged Thus Group plc (“Thus”). The demerger of Thus was preceeded by an open offer of approximately £275 million of new equity shares in Thus which resulted in ScottishPower’s equity interest in Thus temporarily increasing from 50.1% to 72.4%, and an increase in goodwill of £34.4 million. Thus’ results for the period to 19 March 2002 have been reported under discontinued operations in the ScottishPower accounts for the year ended 31 March 2002 and prior years. The demerger of Thus was accounted for as a dividend in specie.

	Notes	£m
Intangible fixed assets—goodwill	16	62.6
Tangible fixed assets	17	468.8
Fixed assets investments	18	24.2
Current assets		104.5
Creditors: amounts falling due within one year		(109.9	)
Provisions for liabilities and charges —Other provisions	23	(0.9	)
Book value of Thus net assets disposed		549.3
Minority interest share of net assets	28	(127.4	)
ScottishPower’s share of Thus net assets disposed		421.9
Goodwill previously charged to reserves written back	27	14.7
Dividend in specie		436.6

34    Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’)

The consolidated Accounts of the group are prepared in accordance with UK GAAP which differs in certain significant respects from US GAAP. The effect of the US GAAP adjustments to (loss)/profit for the financial year and equity shareholders’ funds are set out in the tables below.

(a)  Reconciliation of (loss)/profit for the financial year to US GAAP:

	Year ended 31 March
	Notes		2002 £m		2001 £m		2000 £m
(Loss)/profit for the financial year under UK GAAP			(987.1	)	307.5		885.0
US GAAP adjustments:
Amortisation of goodwill	(i	)	(23.5	)	(35.9	)	(34.4	)
Disposal of businesses	(ii	)	279.1		—		—
US regulatory assets	(iii	)	95.3		73.8		—
Pensions	(iv	)	40.0		95.5		44.8
Impairment on demerger of Thus	(v	)	(243.7	)	—		—
Depreciation on revaluation uplift	(vi	)	3.4		3.4		3.4
Decommissioning and mine reclamation liabilities	(vii	)	(21.8	)	(32.3	)	(6.7	)
PacifiCorp Transition Plan costs	(viii	)	(29.9	)	108.2		—
FAS 133 adjustment	(ix	)	144.5		—		—
Other	(xvi	)	(17.7	)	(0.4	)	(8.0	)
Re-classification as extraordinary item	(x	)	12.0		—		15.9
			(749.4	)	519.8		900.0
Deferred tax effect of US GAAP adjustments	(xi	)	(67.6	)	(133.0	)	(19.2	)
			(817.0	)	386.8		880.8
Extraordinary item (net of tax)	(x	)	(8.4	)	—		(11.1	)
(Loss)/profit for the financial year under US GAAP before cumulative adjustment for FAS 133			(825.4	)	386.8		869.7
Cumulative adjustment for FAS 133	(ix	)	(61.6	)	—		—
(Loss)/profit for the financial year under US GAAP			(887.0	)	386.8		869.7
(Loss)/earnings per share under US GAAP	(xiv	)	(44.91	)p	21.13	p	62.59	p
Diluted (loss)/earnings per share under US GAAP	(xiv	)	(44.91	)p	21.05	p	62.16	p
(Loss)/earnings per share under US GAAP have been calculated before the cumulative adjustment for FAS 133.

97

NOTES TO THE GROUP BALANCE SHEET

as at 31 March 2002—continued

(b)  Effect on equity shareholders’ funds of differences between UK GAAP and US GAAP:

	Notes		31 March 2002 £m		31 March 2001 £m
Equity shareholders’ funds under UK GAAP			4,731.4		5,893.2
US GAAP adjustments:
Goodwill	(i	)	572.3		1,349.9
Business combinations	(i	)	(174.2	)	(188.7	)
Amortisation of goodwill	(i	)	(84.2	)	(172.7	)
ESOP shares held in trust	(xii	)	(38.9	)	(51.1	)
US regulatory assets	(iii	)	1,042.8		661.2
Pensions	(iv	)	222.9		245.0
Cash dividends	(xiii	)	126.1		119.4
Revaluation of fixed assets	(vi	)	(54.0	)	(229.0	)
Depreciation on revaluation uplift	(vi	)	8.5		11.9
Decommissioning and mine reclamation liabilities	(vii	)	60.7		82.5
PacifiCorp Transition Plan costs	(viii	)	86.9		117.2
FAS 133 adjustment	(ix	)	(308.2	)	—
Other	(xvi	)	(3.4	)	12.1
Deferred tax:
Effect of US GAAP adjustments	(xi	)	(316.9	)	(351.0	)
Effect of differences in methodology	(xi	)	(21.3	)	(37.0	)
Equity shareholders’ funds under US GAAP			5,850.5		7,462.9

(i) Goodwill and business combinations

Goodwill

Under UK GAAP, goodwill arising from the purchase of operating entities before 31 March 1998 has been written off directly to reserves. Additionally, UK GAAP requires that on subsequent disposal of these entities any goodwill previously taken directly to reserves is then charged in the profit and loss account against the profit or loss on disposal. Goodwill arising on acquisitions after 31 March 1998 is capitalised and amortised through the profit and loss account over its useful economic life.

Under US GAAP, goodwill arising from the purchase of operating entities should be held as an intangible asset in the balance sheet and amortised over its expected useful life.

The goodwill adjustment is made to recognise goodwill previously written off to reserves under UK GAAP as an intangible asset under US GAAP.

This goodwill, which is capitalised under US GAAP, is then amortised on a straight line basis over its estimated useful life of 40 years with the effect being a reduction in profit reflecting the amortisation charge for the period.

Business combinations

In addition to re-instating the goodwill calculated under UK GAAP as described above, goodwill must also be recalculated in accordance with US GAAP. This is required due to differences between UK GAAP and US GAAP in the determination of acquisition price and valuation of assets and liabilities at the acquisition date. The adjustment referred to as business combinations reflects principally the impact of recalculating the goodwill arising on the acquisitions of Manweb and PacifiCorp under US GAAP.

In cases where traded equity securities are exchanged as consideration, UK GAAP requires the fair value of consideration to be determined at the date the transaction is completed, while US GAAP requires the fair value of such consideration to be determined at the date the acquisition is announced.

(ii) Disposal of businesses

Under UK GAAP the loss on disposal of and withdrawal from Appliance Retailing and the provision for loss on disposal of Southern Water were calculated based on net asset value, together with the goodwill previously written off to reserves.

Under US GAAP the same methodology was applied, however the net asset value under US GAAP differed from that under UK GAAP. The principal differences relate to the amortisation of goodwill which had been recognised as an intangible asset under US GAAP but had been written off to reserves under UK GAAP and the revaluation of certain tangible fixed assets, which is not permitted under US GAAP but is permitted under UK GAAP.

(iii) US regulatory assets

Statement of Financial Accounting Standards (“FAS”) 71 ‘Accounting for the Effects of Certain Types of Regulation’ establishes US GAAP for utilities in the US whose regulators have the power to approve and/or regulate rates that may be charged to customers. Provided that, through the regulatory process, the utility is substantially assured of recovering its allowable costs by the collection of revenue from its customers, such costs not yet recovered are deferred as regulatory assets. Due to the different regulatory environment, no equivalent GAAP applies in the UK.

Under UK GAAP, the group’s policy is to recognise regulatory assets established in accordance with FAS 71 only where they comprise rights or other access to future economic benefits which have arisen as a result of past transactions or events which have created an obligation to transfer economic benefits to a third party.

The impact of the application of different accounting policies is that US regulatory assets amounting to £1,042.8 million (2001 £661.2 million) are not recognised under UK GAAP, including deferred excess power costs and certain FAS 133 balances.

Profits under US GAAP are consequently increased by £95.3 million in 2002 (2001 £73.8 million), representing the deferral of costs expensed under UK GAAP net of amortisation of regulatory assets recognised under US GAAP.

US regulatory assets relating to the PacifiCorp Transition Plan costs are discussed in note (viii) below.

(iv) Pension costs

The fundamental differences between UK GAAP and US GAAP are as follows:

(a) Under UK GAAP, the annual pension charge is determined so that it is a substantially level percentage of the current and expected future payroll. Under US GAAP, the aim is to accrue the cost of providing pension benefits in the year in which the employee provides the related service in accordance with FAS 87, which requires readjustment of the significant actuarial assumptions annually to reflect current market and economic conditions.

(b) Under UK GAAP, pension liabilities are usually discounted using an interest rate that represents the expected long-term return on plan assets. Under US GAAP, pension liabilities are discounted using the current rates at which the pension liability could be settled.

(c) Under UK GAAP, variations from plan can be aggregated and amortised over the remaining employee service lives. Under US GAAP, variations from plan must be amortised separately over remaining service lives.

(d) Under UK GAAP, alternative bases can be used to value plan assets. Under US GAAP, plan assets should be valued at market or at market related values.

(v) Impairment on demerger of Thus

Under UK GAAP, the demerger dividend is calculated based on the book value of the net assets disposed of as a result of the demerger.

Under US GAAP, the demerger dividend is calculated based on the market value of the shares at the demerger date and the difference between this and the book value of net assets disposed of is disclosed as an impairment charge under US GAAP.

98

(vi) Revaluation of fixed assets

The revaluation of assets is not permitted under US GAAP. Accordingly, the reconciliation restates fixed assets to historical cost and the depreciation charge has been adjusted.

(vii) Decommissioning and mine reclamation liabilities

Under UK GAAP, future decommissioning costs are provided for, on a discounted basis, generally at the inception of the asset life with a corresponding increase to the cost of the asset. This increased cost is depreciated over the useful life of the asset. Under US GAAP, for regulated industries, decommissioning costs are accounted for by depreciating the related tangible fixed asset to a negative amount which equates to the estimated decommissioning costs. In respect of mine reclamation costs UK GAAP requires the discounted future costs of reclamation to be provided for, with a corresponding increase to the cost of the mine assets. Under US GAAP, anticipated mine reclamation costs are accrued over the life of the mine asset.

(viii) PacifiCorp Transition Plan costs

Under UK GAAP, PacifiCorp Transition Plan costs were recognised as an expense in the profit and loss account at the date of the announcement of the Plan. Costs were provided for in accordance with FRS 12 ‘Provisions, contingent liabilities and contingent assets’.

Under US GAAP, PacifiCorp Transition Plan costs are accounted for as regulatory assets and are being amortised through the income statement. Costs have been provided for in accordance with Emerging Issues Task Force No. 94-3 ‘Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)’ and FAS 88 ‘Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits’.

(ix) FAS 133—derivative instruments and hedging activities

Under UK GAAP derivatives designated as used for non-trading purposes are accounted for on a consistent basis with the asset, liability or position being hedged. Under US GAAP, the group adopted FAS 133 ‘Accounting for Derivative Instruments and Hedging Activities,’ as amended by FAS 137 ‘Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB Statement No. 133’ and FAS 138 ‘Accounting for Certain Derivative Instruments and Certain Hedging Activities’, with effect from 1 April 2001. The transitional adjustment at this date has been reported as the cumulative adjustment for FAS 133. FAS 133 requires recognition of all derivatives, as defined in the standard, on the balance sheet at fair value. Derivatives, or any portion thereof, that are not an effective hedge, are adjusted to fair value through income. If a derivative qualifies as an effective hedge, changes in the fair value of the derivative are either offset against the change in fair value of the hedged asset, liability, or firm commitment recognised in income, or are recognised in accumulated other comprehensive income until the hedged items are recognised in earnings. The effects of changes in fair value of certain derivative instruments entered into to hedge future retail resource requirements in the group’s US regulated business are subject to regulation and therefore are deferred pursuant to FAS 71. Contracts that qualify as normal purchases and normal sales are excluded from the requirements of FAS 133. The realised gains and losses on these contracts are reflected in the income statement at the contract settlement date. The total FAS 133 adjustment included within equity shareholders’ funds of £308.2 million at 31 March 2002 is offset by £328.9 million included within US regulatory assets relating to PacifiCorp’s regulated activities which have been deferred as a regulatory asset under FAS 71 on the basis of approvals received from Public Utility Commissions to adopt this accounting treatment.

(x) Extraordinary item

Under UK GAAP, certain costs of early debt repayment have been treated as exceptional interest costs. Under US GAAP, costs of early debt repayment are classified as extraordinary items. The tax credit on the extraordinary item was £3.6 million for the year ended 31 March 2002 and £4.8 million for the year ended 31 March 2000.

(xi) Deferred tax

Under UK GAAP, FRS 19 ‘Deferred tax’, requires full provision for deferred tax at future enacted rates. Provision is only made in respect of assets revalued for accounting purposes where a commitment exists to sell the asset at the balance sheet date.

Under US GAAP, full provision for deferred tax is required to the extent that accounting profit differs from taxable profit due to temporary timing differences. Provision is made based on enacted tax law.

The item ‘effect of US GAAP adjustments’ reflects the additional impact of making full provision for deferred tax in respect of adjustments made in restating the balance sheet to US GAAP.

        The item ‘effect of differences in methodology’ reflects the impact of making full provision for deferred tax under US GAAP compared to UK GAAP.

(xii) ESOP shares held in trust

Under UK GAAP, shares held by employee share ownership trusts are recorded as fixed asset investments at cost less amounts written off. Under US GAAP, shares held in trust are recorded at cost in the balance sheet as a deduction from shareholders’ funds. Details of the group’s employee share ownership trusts are set out in Note 18.

(xiii) Cash dividends

Under UK GAAP, final ordinary cash dividends are recognised in the financial year in respect of which they are proposed by the Board of Directors. Under US GAAP, such dividends are not recognised until they are formally declared by the Board of Directors.

(xiv) (Loss)/earnings per share

(Loss)/earnings per ordinary share have been calculated by dividing the (loss)/profit for the financial year under US GAAP by the weighted average number of ordinary shares in issue during the financial year, based on the following information:

	2002		2001		2000
(Loss)/profit for the financial year under US GAAP million)	(887.0	)	386.8		869.7
Basic weighted average share capital (number of shares, millions)	1,837.8		1,830.3		1,389.6
Diluted weighted average share capital (number of shares, millions)	1,840.1		1,837.4		1,399.2
(Loss)/earnings per share
Earnings per share under US GAAP—continuing operations	19.15	p	13.48	p	4.89	p
(Loss)/earnings per share under US GAAP—discontinued operations	(63.60	)p	7.65	p	58.49	p
Loss per share under US GAAP—extraordinary item (net of tax)	(0.46	)p	—		(0.79	)p
(Loss)/earnings per share under US GAAP before cumulative adjustment for FAS 133	(44.91	)p	21.13	p	62.59	p
Loss per share under US GAAP—cumulative adjustment for FAS 133	(3.35	)p	—		—
(Loss)/earnings per share under US GAAP	(48.26	)p	21.13	p	62.59	p
Diluted (loss)/earnings per share
Diluted earnings per share under US GAAP—continuing operations	19.15	p	13.43	p	4.86	p
Diluted (loss)/earnings per share under US GAAP—discontinued operations	(63.60	)p	7.62	p	58.09	p
Diluted loss per share under US GAAP—extraordinary item (net of tax)	(0.46	)p	—		(0.79	)p
Diluted (loss)/earnings per share under US GAAP before cumulative adjustment for FAS 133	(44.91	)p	21.05	p	62.16	p
Diluted loss per share under US GAAP—cumulative adjustment for FAS 133	(3.35	)p	—		—
Diluted (loss)/earnings per share under US GAAP	(48.26	)p	21.05	p	62.16	p

99

NOTES TO THE GROUP BALANCE SHEET

as at 31 March 2002—continued

The difference between the basic and the diluted weighted average share capital is wholly attributable to outstanding share options and shares held in trust for the group’s Employee Share Ownership Plan. In accordance with FAS 128 ‘Earnings per Share’ the diluted loss per share for the year ended 31 March 2002 does not assume the exercise of securities that have an antidilutive effect on the loss per share. The (loss)/earnings per share detailed above for discontinued operations have been calculated based on US GAAP earnings which are net of £37.0 million (2001 £36.3 million, 2000 £18.0 million) of interest and similar charges and tax charges of £18.8 million (2001 £5.8 million tax credit, 2000 £149.3 million tax charge). The group’s charge for interest and similar charges has been allocated between continuing and discontinued operations on the basis of external and internal borrowings of the respective operations.

(xv) Additional measures of performance

As permitted under UK GAAP, (loss)/earnings per share have been presented including and excluding the impact of exceptional items and goodwill amortisation to provide an additional measure of underlying performance. UK GAAP permits the presentation of more than one measure of (loss)/earnings per share provided that all such measures are clearly explained and given equal prominence on the face of the profit and loss account. In accordance with US GAAP, (loss)/earnings per share have been presented above based on US GAAP (loss)/earnings, without adjustments for the impact of UK GAAP exceptional items and goodwill amortisation. Such additional measures of underlying performance are not permitted under US GAAP.

(xvi) Other

Other differences between UK and US GAAP are not individually material and relate to post-retirement benefits other than pensions, capitalisation of finance costs, available-for-sale securities, energy exchange contracts and stock based compensation expense.

UK GAAP permits the use of long-term discount rates in determining the provision for post-retirement benefits other than pensions. US GAAP requires the use of current market rates.

Under UK GAAP, only interest on debt funding may be capitalised during the period of construction. Under US GAAP, as applied by regulated electricity utilities, both the cost of debt and the cost of equity applicable to domestic utility properties are capitalised during the period of construction.

Under UK GAAP, obligations under energy exchange contracts are valued based on the forecast cost at the balance sheet date of delivering energy under the contract. Under US GAAP, for regulated utilities, obligations under energy exchange contracts are valued based on the cost avoided in receiving delivery of energy under the contract.

Available-for-sale securities

UK GAAP permits current asset investments to be valued at the lower of cost and net realisable value. US GAAP requires that such investments, insofar as they are available-for-sale securities, are marked-to-market with movements in market value being included in other comprehensive income.

The book value and estimated fair value of available-for-sale securities were as follows:

		At 31 March 2002
	Book value £m	Gross unrealised gains £m	Gross unrealised losses £m		Estimated fair value £m
Money market account	1.9	—	—		1.9
Debt securities	14.4	0.3	(1.8	)	12.9
Equity securities	27.7	2.7	(5.3	)	25.1
Total	44.0	3.0	(7.1	)	39.9

		At 31 March 2001
	Book value £m	Gross unrealised gains £m	Gross unrealised losses £m		Estimated fair value £m
Money market account	1.9	—	—		1.9
Debt securities	13.6	0.3	(1.7	)	12.2
Equity securities	29.7	3.8	(6.7	)	26.8
Total	45.2	4.1	(8.4	)	40.9

The quoted market price of securities at 31 March is used to estimate the securities’ fair value.

The book value and estimated fair value of debt securities by contractual maturities at 31 March 2002 and 2001 are shown below. Actual maturities may differ from contractual maturities because borrowers may have the right to call or pre-pay obligations with or without call or prepayment penalties.

	At 31 March 2002		At 31 March 2001
	Book value £m	Estimated fair value £m	Book value £m	Estimated fair value £m
Debt securities
Due within one year	—	—	0.4	0.4
Due between one and five years	3.2	2.9	3.5	3.2
Due between five and ten years	4.6	4.4	3.8	3.4
Due after ten years	6.6	5.6	5.9	5.2
Money market account	1.9	1.9	1.9	1.9
Equity securities	27.7	25.1	29.7	26.8
Total	44.0	39.9	45.2	40.9

Proceeds, gross gains and gross losses from realised sales of available-for-sale securities using the specific identification method were as follows:

	Year ended 31 March
	2002 £m		2001 £m		2000 £m
Proceeds	56.4		54.0		52.0
Gross gains	2.1		5.3		3.4
Gross losses	(5.6	)	(3.6	)	(2.1	)
Net (losses)/gains	(3.5	)	1.7		1.3

100

FAS 123 Stock-Based Compensation

Under US GAAP, the group applies Accounting Principles Board Opinion No. 25 (“APB 25”), ‘Accounting for Stock Issued to Employees’, and related interpretations in accounting for its plans and a compensation expense has been recognised accordingly for its Share Option Schemes. As the group applies APB 25 in accounting for its plans, under FAS 123, ‘Accounting for Stock-Based Compensation’, it has adopted the disclosure only option in relation to its Share Option Schemes. Had the group determined compensation cost based on the fair value at the grant date for its share options under FAS 123, the group’s (loss)/profit for financial year under US GAAP and (loss)/earnings per share under US GAAP would have been reduced to the pro forma amounts below:

	2002		2001		2000
(Loss)/profit for financial year under US GAAP (£million)	(887.0	)	386.8		869.7
Pro forma (£million)	(890.0	)	380.6		864.6
(Loss)/earnings per share under US GAAP	(48.26	)p	21.13	p	62.59	p
Pro forma	(48.43	)p	20.79	p	62.22	p

The weighted average fair value of options granted during the year was £1.6 million (2001 £8.6 million, 2000 £8.7 million). The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions used:

	2002		2001		2000
Dividend yield	6.7	%	6.4	%	4.5	%
Risk-free interest rate	4.8	%	4.9	%	6.0	%
Volatility	30.0	%	24.0	%	30.0	%
Expected life of the options (years)	4		4		4

The weighted average life of the share options outstanding as at 31 March 2002, March 2001 and March 2000 was as follows:

	2002 (years)	2001 (years)	2000 (years)
ScottishPower Sharesave Schemes	3	2	3
Southern Water Sharesave Scheme	2	2	2
Executive Share Option Scheme	2	2	2
Executive Share Option Plan 2001	9	—	—
PacifiCorp Stock Incentive Plan	6	6	8

(xvi) Reclassifications

The reconciliations of (loss)/profit for the financial year and equity shareholders’ funds at the year end from UK GAAP to US GAAP only include those items which have a net effect on (loss)/profit or equity shareholders’ funds. There are other GAAP differences, not included in the reconciliations, which would affect the classification of assets and liabilities or of income and expenditure. The principal items which would have such an effect are as follows:

— under UK GAAP debt issue costs are deducted from the carrying value of the related debt instrument. US GAAP requires such costs to be included as an asset

— under UK GAAP customer contributions in respect of fixed assets are generally credited to a separate deferred income account. Under US GAAP such contributions are netted off against the cost of the related fixed assets

— items included as exceptional items under UK GAAP are either classified as extraordinary items or operating items under US GAAP

— under US GAAP, transmission and distribution costs would be included in cost of sales, and gross profit from continuing operations would be calculated after deducting these expenses

— under UK GAAP, the investor’s interest in the turnover and results of a joint venture or associate are disclosed gross. The investor’s share of the interest and taxation are disclosed separately as a component of the group interest and taxation lines. Under US GAAP, the investor’s interest in the net results of joint ventures and associates is disclosed as a single line in the income statement, net of interest and taxation.

Consolidated statement of comprehensive income

Under US GAAP, certain items shown as components of common equity must be more prominently reported in a separate statement as components of comprehensive (loss)/income.

The consolidated statement of comprehensive (loss)/income is set out below:

	2002 £m		2001 £m		2000 £m
(Loss)/profit for the financial year under US GAAP after cumulative adjustment for FAS 133	(887.0	)	386.8		869.7
Other comprehensive (loss)/income
—Foreign currency translation adjustment	(29.7	)	671.2		25.1
—Unrealised (loss)/gain on available-for-sale securities, net of tax credit/(charge) of £0.1 million (2001 £4.0 million, 2000 £(2.1) million)	(0.1	)	(6.5	)	3.4
—Pensions, net of tax credit of £23.6 million	(38.5	)	—		—
—Cumulative effect of accounting change—FAS 133, net of tax charge of £261.4 million	421.3		—		—
—FAS 133—loss on derivative financial instruments recognised in net income, net of tax credit of £47.6 million	(76.6	)	—		—
—FAS 133—unrealised loss on derivative financial instruments, net of tax credit of £219.9 million	(354.7	)	—		—
Total comprehensive (loss)/income under US GAAP	(965.3	)	1,051.5		898.2

The accumulated balances related to each component of other comprehensive (loss)/income are as follows:

	2002 £m		2001 £ m		2000 £m
Foreign currency translation adjustment	666.6		696.3		25.1
Unrealised (loss)/gain on available-for-sale securities, net of tax credit of £2.0 million	(3.2	)	(3.1	)	3.4
Pensions, net of tax credit of £23.6 million	(38.5	)	—		—
Unrealised loss on derivative financial instruments, net of tax credit of £6.1 million	(10.0	)	—		—

Consolidated statement of cash flows

The consolidated statement of cash flows prepared in accordance with FRS 1 (Revised) presents substantially the same information as that required under US GAAP. Under US GAAP, however, there are certain differences from UK GAAP with regard to the classification of items within the cash flow statement and with regard to the definition of cash and cash equivalents.

Under UK GAAP, cash flows are presented separately for operating activities, dividends received from joint ventures, returns on investments and servicing of finance, taxation, capital expenditure and financial investment, acquisitions and disposals, equity dividends paid, management of liquid resources, and financing. Under US GAAP, only three categories of cash flow activity are reported; operating activities, investing activities and financing activities. Cash flows from dividends received from joint ventures, returns on investments and servicing of finance and taxation would be included as operating activities under US GAAP. Equity dividends paid would be included under financing activities under US GAAP.

Under US GAAP, cash and cash equivalents are not offset by bank overdrafts repayable within 24 hours from the date of the advance, as is the case under UK GAAP and instead such bank overdrafts are classified within financing activities.

101

NOTES TO THE GROUP BALANCE SHEET

as at 31 March 2002—continued

The consolidated cash flow statement prepared in conformity with UK GAAP is set out on page 71. In this statement an additional measure, free cash flow, is included which is not an accepted measure under US GAAP. This measure represents cash flow from operations after adjusting for dividends received from joint ventures, returns on investments and servicing of finance and taxation. UK investors regard free cash flow as the money available to management annually to be allocated among a number of options including capital expenditure, payments of dividends and the financing of acquisitions.

The consolidated statement of cash flows under US GAAP is set out below:

	2002 £m		2001 £m		2000 £m
Cash inflow from operating activities	1,248.4		1,411.6		1,117.5
Dividends received from joint ventures	0.3		2.1		0.5
Returns on investments and servicing of finance	(377.8	)	(373.5	)	(258.4	)
Taxation	(85.0	)	(152.6	)	(154.3	)
Net cash provided by operating activities	785.9		887.6		705.3
Capital expenditure and financial investment	(1,148.3	)	(1,081.4	)	(842.3	)
Acquisitions and disposals	98.7		482.9		718.8
Net cash used in investing activities	(1,049.6	)	(598.5	)	(123.5	)
Financing	929.1		196.1		(121.2	)
Movement in bank overdrafts	(17.8	)	11.1		23.8
Equity dividends paid	(496.8	)	(471.3	)	(406.0	)
Net cash provided/(required) by financing activities	414.5		(264.1	)	(503.4	)
Net increase in cash and cash equivalents	150.8		25.0		78.4
Exchange movement on cash and cash equivalents	(0.2	)	19.9		—
Cash and cash equivalents at beginning of financial year	230.2		185.3		106.9
Cash and cash equivalents at end of financial year	380.8		230.2		185.3

All liquid investments with maturities of three months or less at the time of acquisition are considered to be cash equivalents.

Significant non-cash investing or financing activities

	2002 £m	2001 £m	2000 £m
On acquisition of subsidiary: shares allotted as part of purchase consideration	—	—	4,065.5
Share of debt in joint arrangement	100.5	—	—

Additional information required under US GAAP

(a)  Infrastructure accounting

The group’s accounting policy in respect of Southern Water’s infrastructure assets and related maintenance and renewals expenditure, as set out and explained in the accounting policies, is not generally accepted under US GAAP which requires historical cost depreciation accounting for these assets. The difference between the infrastructure renewals depreciation charge and depreciation accounting under US GAAP is not material to profit and equity shareholders’ funds.

(b) Doubtful debts

        The group provided £57.5 million, £29.7 million and £45.2 million for doubtful debts in 2002, 2001 and 2000 respectively. Write-offs against the provision for doubtful debts for uncollectable amounts were £36.6 million, £26.1 million and £31.3 million in 2002, 2001 and 2000 respectively.

(c) Deferred tax

The additional components of the estimated net deferred tax liability that would be recognised under US GAAP are as follows:

	2002 £m		2001 £m
Deferred tax liabilities:
Excess of book value over taxation value of fixed assets	142.6		186.0
Other temporary differences	200.7		208.0
	343.3		394.0
Deferred tax assets:
Other temporary differences	(5.1	)	(6.0	)
Net deferred tax liability	338.2		388.0
Analysed as follows:
Current	(5.1	)	(6.0	)
Non-current	343.3		394.0
	338.2		388.0

The deferred tax balance in respect of leveraged leases at the year end is £145.1x million (2001 £162.7 million).

Investment tax credits for PacifiCorp are deferred and amortised to income over periods prescribed by the group’s various regulatory jurisdictions under US GAAP.

(d) Pensions

At 31 March 2002, ScottishPower had eight statutorily approved defined benefit pension schemes and one statutorily approved defined contribution scheme. The PacifiCorp arrangements are included following the acquisition of PacifiCorp on 29 November 1999.

Benefits under the UK defined benefit plans reflect each employee’s basic earnings, years of service and age at retirement. Funding of the defined benefit plans is based upon actuarially determined contributions, with members paying contributions at fixed rates and the employers meeting the balance of cost as determined by the scheme actuaries.

Under the defined contribution plan, contributions are paid by the member and employer at a fixed rate. Benefits under the defined contribution plan reflect each employee’s fund at retirement and the cost of purchasing benefits at that time.

102

Reconciliations of the beginning and ending balances of the projected pension benefit obligation and the funded status of these plans for the years ending 31 March 2002, 31 March 2001 and 31 March 2000 are as follows:

Change in benefit obligation	2002 £m		2001 £m		2000 £m
Benefit obligation at beginning of year	3,051.0		2,827.6		2,074.2
Additional obligation from acquisition	—		—		673.6
Service cost (excluding plan participants’ contributions)	62.2		66.6		57.6
Interest cost	182.5		179.8		137.7
Plan amendments	12.6	*	(15.7	)	—
Special termination benefits	0.6	**	54.8		—
Plan participants’ contributions	11.9		12.9		12.9
Actuarial loss/(gain)	29.0		27.4		(8.3	)
Benefits paid	(209.5	)	(187.0	)	(124.9	)
Transfers	(29.0	)***	—		—
Exchange	0.9		84.6		4.8
Benefit obligation at end of year	3,112.2		3,051.0		2,827.6

* Ad hoc cost of living benefit increase for certain retired employees that was approved 13 March 2002.

** The acquisition of PacifiCorp by ScottishPower triggered special termination benefits from the SERP during 2002.

*** Assets and liabilities were transferred to the PacifiCorp/International Brotherhood of Electrical Workers Local Union 57 Retirement Trust Fund.

Change in plans’ assets	2002 £m		2001 £m		2002 £m
Fair value of plans’ assets at beginning of year	3,586.6		3,886.8		2,781.4
Additional fair value of assets from acquisition	—		—		636.1
Actual return on plans’ assets	(163.0	)	(248.2	)	558.3
Employer contributions	18.5		32.7		17.7
Plan participants’ contributions	11.9		12.9		12.9
Benefits paid	(209.5	)	(187.0	)	(124.9	)
Transfers	(39.4	)	—		—
Exchange	(0.5	)	89.4		5.3
Fair value of plans’ assets at end of year	3,204.6		3,586.6		3,886.8

Reconciliation of funded status to prepaid benefit cost	2002 £m		2001 £m		2000 £m
Funded status	92.4		535.6		1,059.2
Unrecognised net actuarial loss/(gain)	121.9		(348.9	)	(933.5	)
Unrecognised prior service cost	(1.5	)	(15.2	)	—
Unrecognised Transition Obligation Asset	(1.6	)	(2.5	)	(3.3	)
Prepaid benefit cost	211.2		169.0		122.4

Amounts recognised in balance sheet (UK arrangements)	2002 £m	2001 £m	2000 £m
Prepaid benefit cost	270.4	237.4	151.5
Total recognised	270.4	237.4	151.5

Amounts recognised in balance sheet (US arrangements)	2002 £m		2001 £m		2000 £m
Accrued benefit liability	(121.3	)	(68.4	)	(29.1	)
Accumulated other comprehensive income	62.1		—		—
Total recognised	(59.2	)	(68.4	)	(29.1	)

The value of plan assets exceed the accumulated benefit obligation at the end of the year except in the following cases:

Plan	Value of plan assets at 31 March 2002 £m	Accumulated benefit obligation at 31 March 2002 £m
Southern Water	278.3	284.3
PacifiCorp	581.8	700.8

For all plans in 2000/01, the value of plan assets exceeded the accumulated benefit obligation at the end of the year.

The value of plan assets exceed the projected benefit obligation at the end of the year except in the following cases:

Plan	Value of plan assets at 31 March 2002 £m	Projected benefit obligation at 31 March 2002 £m
Final Salary LifePlan	10.2	11.6
Southern Water	278.3	317.7
PacifiCorp	581.8	760.1

103

NOTES TO THE GROUP BALANCE SHEET

as at 31 March 2002—continued

The components of pension benefit costs for the years ended 31 March 2002, 2001 and 2000 were as follows (figures for 2000 include post-acquisition period only for PacifiCorp):

	31 March 2002 £m		31 March 2001 £m		31 March 2000* £m
Service cost	62.2		66.6		57.6
Interest cost	182.5		179.8		137.7
Expected return on plans’ assets	(261.2	)	(287.2	)	(211.1	)
Amortisation of experience gains	(5.8	)	(36.0	)	(22.8	)
Amortisation of prior service cost	(1.1	)	(1.1	)	–
Amortisation of Transition Obligation Asset	(0.9	)	(0.8	)	(0.8	)
Net periodic benefit credit	(24.3	)	(78.7	)	(39.4	)

* For the post-acquisition period (29 November 1999 to 31 March 2000)

The actuarial assumptions adopted in arriving at the above figures are as follows:

UK arrangements—assumptions at:	31 March 2002	31 March 2001	31 March 2000
Expected return on plans’ assets	7.5% p.a.	7.0% p.a.	7.0% p.a.
Discount rate	6.0% p.a.	5.75% p.a.	6.0% p.a.
Rate of earnings increase	4.3% p.a.	4.5% p.a.	5.0% p.a.
Pension increases	2.8% p.a.	2.5% p.a.	3.0% p.a.

US arrangements—assumptions at:	31 March 2002	31 March 2001	31 March 2000
Expected return on plans’ assets	9.25% p.a.	9.25% p.a.	9.25% p.a.
Discount rate	7.5% p.a.	7.75% p.a.	7.5% p.a.
Rate of earnings increase	4.0% p.a.	4.0% p.a.	4.0% p.a.
Inflation rates	4.0% p.a.	4.0% p.a.	4.0% p.a.

(e)  Other post-retirement benefits

PacifiCorp provides healthcare and life insurance benefits through various plans for eligible retirees on a basis substantially similar to those who are active employees. The cost of post-retirement benefits is accrued over the active service period of employees. For those employees retired at 1 January 1994, PacifiCorp funds post-retirement benefit expense on a pay-as-you-go basis and has an unfunded accrued liability of £127.9 million at 31 March 2002. For those employees retiring on or after 1 January 1994, PacifiCorp funds post-retirement benefit expense through a combination of funding vehicles: PacifiCorp did not fund over the period 1 April 2001 to 31 March 2002. These funds are invested in common stocks, bonds and US government obligations. The figures below relate to the combined position for the unfunded and funded arrangements.

The net periodic post-retirement benefit cost and significant assumptions are summarised as follows:

	2002 £m		2001 £m		2000* £m
Service cost	3.6		3.5		1.2
Interest cost	20.0		18.8		5.1
Expected return on plan assets	(20.4	)	(19.1	)	(4.6	)
Net periodic post-retirement benefit cost	3.2		3.2		1.7

* For the post-acquisition period (29 November 1999 to 31 March 2000)

The change in the accumulated post-retirement benefit obligation, change in plan assets and funded status are as follows:

	2002 £m		2001 £m		2000* £m
Change in accumulated post-retirement benefit obligation
Accumulated post-retirement benefit obligation at beginning of year	268.0		220.3		215.9	**
Service cost	3.6		3.5		1.2
Interest cost	20.0		18.8		5.1
Plan participants’ contributions	3.8		3.2		0.6
Special termination benefit loss	—		11.4		—
Actuarial loss/(gain)	53.8		(3.1	)	(0.3	)
Benefits paid	(18.8	)	(13.6	)	(3.7	)
Exchange	0.9		27.5		1.5
Accumulated post-retirement benefit obligation at end of year	331.3		268.0		220.3

	2002 £m		2001 £m		2000* £m
Change in plan assets
Plan assets at fair value at beginning of year	201.9		200.2		163.9	**
Actual return on plan assets	(12.6	)	(18.2	)	31.0
Company contributions	10.4		6.8		7.0
Plan participants’ contributions	3.8		3.2		0.6
Benefits paid	(18.8	)	(13.6	)	(3.7	)
Exchange	0.2		23.5		1.4
Plan assets at fair value at end of year	184.9		201.9		200.2

* For the post-acquisition period (29 November 1999 to 31 March 2000)

** As at acquisition — 29 November 1999

	2002 £m		2001 £m		2000 £m
Reconciliation of accrued post-retirement costs and total amount recognised
Funded status of plan	(146.4	)	(66.1	)	(20.1	)
PacifiCorp unrecognised net loss/(gain)	93.5		6.0		(26.4	)
Accrued post-retirement benefit cost	(52.9	)	(60.1	)	(46.5	)

104

The actuarial assumptions adopted in arriving at the above figures are as follows:

	31 March 2002	31 March 2001	31 March 2000
US arrangements—assumptions at:
Expected return on plans’ assets	9.25% p.a.	9.25% p.a.	9.25% p.a.
Discount rate	7.50% p.a.	7.75% p.a.	7.50% p.a.
Initial healthcare cost trend—under 65	10.50% p.a.	6.00% p.a.	6.60% p.a.
Initial healthcare cost trend—over 65	12.50% p.a.	6.50% p.a.	6.80% p.a.
Initial healthcare cost trend rate	5.00% p.a.	4.50% p.a.	4.50% p.a.

The assumed healthcare cost trend rate gradually decreases over five to eight years. The healthcare cost trend rate assumption has a significant effect on the amounts reported. Increasing the assumed healthcare cost trend rate by one percentage point would have increased the accumulated post-retirement benefit obligation (the “APBO”) as of 31 March 2002 by £18.5 million (2001 £13.1 million, 2000 £15.7 million) and the annual net periodic post-retirement benefit costs by £1.3 million (2001 £1.1 million, 2000 £1.4 million). Decreasing the assumed healthcare cost trend rate by one percentage point would have reduced the APBO as of 31 March 2002 by £17.1 million (2001 £16.0 million, 2000 £14.9 million), and the annual net periodic post-retirement benefit costs by £1.2 million (2001 £1.4 million, 2000 £1.3 million).

Post-employment benefits

PacifiCorp provides certain post-employment benefits to former employees and their dependants during the period following employment but before retirement. The costs of these benefits are accrued as they are incurred. Benefits include salary continuation, severance benefits, disability benefits and continuation of healthcare benefits for terminated and disabled employees and workers compensation benefits. The provision for post-employment benefits was £13.5 million at 31 March 2002 (2001 £12.0 million).

Employee savings and stock ownership plan

PacifiCorp has an employee savings and stock ownership plan that qualifies as a tax-deferred arrangement under Section 401(a), 401(k), 409, 501 and 4975(e)(7) of the Internal Revenue Code. Participating US employees may defer up to 20% of their compensation, subject to certain regulatory limitations. PacifiCorp matches a portion of employee contributions with ScottishPower ADSs, vesting that portion over five years. PacifiCorp makes an additional contribution of ScottishPower ADSs to qualifying employees equal to a percentage of the employee’s eligible earnings. These contributions are immediately vested. Employer contributions to the savings plan were £14.7 million for the year ended 31 March 2002 (2001 £12.2 million).

(f)  Southern Water disposal

In April 2002, the group completed the sale of Aspen 4 Limited (the holding company of Southern Water plc) to First Aqua Limited. A summary of the net assets to be disposed of as at 31 March 2002, calculated under US GAAP, are detailed in the table below:

	£m
Tangible fixed assets	2,482.2
Current assets	97.4
Creditors: amounts falling due within one year	(937.1	)
Creditors: amounts falling due after more than one year
Loans and other borrowings	(99.8	)
Provisions for liabilities and charges	(342.4	)
Deferred income	(37.4	)
Net assets	1,162.9

(g)  Environmental, decommissioning and mine reclamation costs

The group’s mining operations in the US are subject to reclamation and closure requirements. Reclamation and closure costs are estimated based on engineering studies. The group monitors these requirements and periodically revises its cost estimates to meet existing legal and regulatory requirements of the various jurisdictions in which it operates.

The group believes that it has adequately provided for its reclamation obligations, assuming ongoing operations of its mines. Total estimated final reclamation costs, including joint owners’ portions, for all mines with which the group is involved was £129.8 million at 31 March 2002. These amounts are expected to be paid over the next 40 years.

The liabilities for environmental, decommissioning and mine reclamation costs are generally recorded on an undiscounted basis. These liabilities are recorded in the UK GAAP balance sheet within ‘Provisions for liabilities and charges’, and balances under US GAAP are detailed below:

	Notes		Balance sheet liability
			31 March 2002 £m	31 March 2001 £m
Environmental costs	(i	)	39.5	43.1
Decommissioning costs	(ii	)	13.2	13.2
Mine reclamation costs	(iii	)	102.4	114.8
Total costs			155.1	171.1

(i) Expected to be paid over 19 years

(ii) Expected to be paid over 22 years

(iii) Amounts include the group’s and joint owners’ portion of mine reclamation costs

The group had trust fund assets of £57.0 million and £58.5 million at 31 March 2002 and 2001, respectively, relating to mine reclamation, including joint owners’ portions.

(h)  Leveraged leases

The pre-tax income from leveraged leases during the year was £4.2 million (2001 £4.3 million), the tax effect of the pre-tax income was £1.4 million (2001 £1.1 million) and the investment tax credit recognised in the income statement was £1.0 million (2001 £0.9 million).

(i) Commitments and contingencies

(i)  Environmental issues

UK businesses

The group’s UK businesses are subject to numerous regulatory requirements with respect to the protection of the environment, including environmental laws which regulate the construction, operation and decommissioning of power stations, pursuant to legislation implementing environmental directives adopted by the EU and protocols agreed under the auspices of international bodies such as the United Nations Economic Commission for Europe. The group believes that it has taken and continues to take measures to comply with applicable laws and regulations for the protection of the environment. Applicable regulations and requirements pertaining to the environment change frequently, however, with the result that continued compliance may require material investments, or that the group’s costs and results of operation are less favourable than anticipated.

US Division—PacifiCorp

PacifiCorp is subject to numerous environmental laws including: the Federal Clean Air Act, as enforced by the Environmental Protection Agency and various state agencies; the 1990 Clean Air Act Amendments; the Endangered Species Act, particularly as it relates to certain potentially endangered species of salmon; the Comprehensive Environmental Response, Compensation and Liability Act, relating to environmental cleanups; along with the Federal Resource Conservation and Recovery Act

105

NOTES TO THE GROUP BALANCE SHEET

as at 31 March 2002—continued

and the Clean Water Act relating to water quality. These laws could potentially impact future operations. For those contingencies identified at 31 March 2002 principally the Superfund sites where PacifiCorp has been or may be designated as a potentially responsible party and Clean Air Act matters, future costs associated with the disposition of these matters are expected to be addressed in future regulatory requests and, therefore, are not expected to have a material impact on the group’s results and financial position.

(ii)  Mine reclamation

US Division—PacifiCorp

All of PacifiCorp’s mining operations are subject to reclamation and closure requirements. Compliance with these requirements could result in higher expenditures for both capital improvements and operating costs.

(iii)  Deferred net power costs

US Division—PacifiCorp

At 31 March 2002, PacifiCorp had deferred net power costs for the states of Utah, Oregon, Wyoming and Idaho. While PacifiCorp is pursuing full recovery of these costs, there can be no assurance that this will be achieved. Denial of recovery would result in the write-off of deferred net power costs, under US GAAP, reported under US regulatory assets in the UK/US GAAP reconciliation of equity shareholders’ funds.

(iv)  Regulation

US Division—PacifiCorp

The Emerging Issues Task Force (“EITF”) of the FASB concluded in 1997 that FAS 71 should be discontinued when detailed legislation or regulatory orders regarding competition are issued. Additionally, the EITF concluded that regulatory assets and liabilities applicable to businesses being deregulated should be written-off unless their recovery is provided through future regulated cash flows. PacifiCorp continuously evaluates the appropriateness of applying FAS 71 to each of its jurisdictions. At 31 March 2002, the group concluded that FAS 71 was appropriate. However, if efforts to deregulate progress, the group may in the future be required to discontinue its application of FAS 71 to all or a portion of its business.

(j)  Derivative Instruments and Hedging Activities

The group uses derivative instruments in the normal course of business, to offset fluctuations in earnings, cash flows and equity associated with movements in exchange rates, interest rates and commodity prices.

FAS 133, ‘Accounting for Derivative Instruments and Hedging Activities’, as amended by FAS 137 and FAS 138 was adopted by the group with effect from 1 April 2001. FAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. FAS 133 requires that an entity recognise all derivatives as either assets or liabilities in the consolidated balance sheet and measure those instruments at fair value. FAS 133 prescribes requirements for designation and documentation of hedging relationships and ongoing assessments of effectiveness in order to qualify for hedge accounting.

Hedge effectiveness is assessed consistently with the method and risk management strategy documented for each hedging relationship. On at least a quarterly basis, the group assesses the effectiveness of each hedging relationship retrospectively and prospectively to ensure that hedge accounting was appropriate for the prior period and continues to be appropriate for future periods. The group applies the short cut method of assessing effectiveness when possible. The group considers hedge accounting to be appropriate if the assessment of hedge effectiveness indicates that the change in fair value of the designated hedging instrument is 80% to 125% effective at offsetting the change in fair value arising on the hedged risk of the hedged item or transaction.

The effect of changes in fair value of certain derivative instruments entered into to hedge PacifiCorp’s future retail resource requirements are subject to regulation in the US and therefore are deferred pursuant to FAS 71. PacifiCorp requested and received deferred accounting orders for the effects of FAS 133 as it relates to the change in value of long-term wholesale electricity contracts not meeting the definition of normal purchases and normal sales contracts.

Categories of derivatives

Derivatives are classified into four categories: fair value hedges, cash flow hedges, overseas net investment hedges and trading.

        If a derivative instrument qualifies as a fair value hedge the change in the fair value of the derivative and the change in the fair value of the hedged risk arising on the hedged item is recorded in earnings. The corresponding change is recorded against the book values of the derivative and hedged item on the balance sheet.

If a derivative instrument qualifies as a cash flow hedge, the effective portion of the hedging instrument’s gain or loss is reported in shareholders’ funds under US GAAP (as a component of accumulated other comprehensive income) and is recognised in earnings in the period during which the transaction being hedged affects earnings. The ineffective portion of the derivative’s fair value change is recorded in earnings.

For derivative instruments designated as a hedge of the foreign currency risk in an overseas net investment, gains or losses due to fluctuations in foreign exchange rates are recorded in the cumulative translation adjustment within shareholders’ funds under US GAAP (as a component of accumulated other comprehensive income).

If a derivative instrument does not qualify as either a net investment hedge or a cash flow hedge under the applicable guidance, the change in the fair value of the derivative is immediately recognised in earnings or as an adjustment to the FAS 71 regulatory asset as appropriate.

Derivative instruments are not generally held by the company for speculative trading purposes. To the extent such instruments are held they are measured at fair value with gains or losses recorded in earnings. The fair value of trading derivatives at 31 March 2002 was £.0 million.

Certain contracts that meet the definition of a derivative under FAS 133 may qualify as a normal purchase or a normal sale and be excluded from the scope of FAS 133. Specific criteria must be met in order for a contract that would otherwise be regarded as a derivative to qualify as a normal purchase or a normal sale. The group has evaluated all commodity contracts to determine if they meet the definition of a derivative and qualify as a normal purchase or a normal sale.

The group also evaluates contracts for “embedded” derivatives, and considers whether any embedded derivatives have to be separated from the underlying host contract and accounted for separately in accordance with FAS 133 requirements. Where embedded derivatives have terms that are not clearly and closely related to the terms of the host contract in which they are included, they are accounted for separately from the host contract as derivatives, with changes in the fair value recorded in earnings, to the extent that the hybrid instrument is not already accounted for at fair value.

Discontinued hedge accounting

When hedge accounting is discontinued due to the group’s determination that the derivative no longer qualifies as an effective fair value hedge, the group will continue to carry the derivative on the balance sheet at its fair value. The related hedged asset or liability will cease to be adjusted for changes in fair value relating to the previously hedged risk.

When the group discontinues hedge accounting in a cash flow hedge because it is no longer probable that the forecasted transaction will occur in the expected period, the gain or loss on the derivative remains in accumulated other comprehensive income and is reclassified into earnings when the forecasted transaction affects earnings. However, if it is probable that a forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter, the gains and losses that were accumulated in other comprehensive income will be recognised in earnings.

Where a derivative instrument ceases to meet the criteria for hedge accounting, any subsequent gains and losses are recognised in earnings.

106

Impact of FAS 133

The cumulative effect of adopting FAS 133 at 1 April 2001, representing the initial valuation of derivatives and other items as described above, was an after-tax charge of £61.6 million included in earnings; an after-tax gain of £421.3 million included in other comprehensive income, a component of shareholders’ funds under US GAAP; and recognition of a regulatory asset relating to the fair value of long-term wholesale contracts subject to regulation in the US of £508.0 million.

Fair value hedges

The group seeks to maintain a desired level of floating rate debt, and uses interest rate and cross currency interest rate swaps to manage interest rate and foreign currency risk arising from long-term debt obligations denominated in sterling and foreign currencies. The group does not exclude any component of derivative gains and losses from the assessment of hedge effectiveness. The ineffective portion of fair value hedges as at 31 March 2002 resulted in a loss of £0.8 million.

Cash flow hedges

On adoption of FAS 133 short-term wholesale electricity purchase contracts not meeting the definition of normal purchases and normal sales contracts were designated as cash flow hedges to hedge the risk of changes in the cost of providing electricity to serve PacifiCorp’s retail load. In June 2001, the Derivatives Implementation Group issued guidance which provided that certain forward power purchase agreements, including capacity contracts, could be excluded from the requirements of FAS 133 by expanding the definition of normal purchases and normal sales exclusion. The group implemented this new guidance, on a prospective basis, with effect from 1 July 2001. As a result, substantially all of PacifiCorp’s short-term wholesale electricity contracts were determined to meet the normal purchases and normal sales exclusion. No further market value changes were recognised for those excluded contracts with unrealised gains or losses in other comprehensive income relating to the existing cash flow hedges as of 1 July 2001 reversed prospectively when the related contract is settled. As of 31 March 2002 the company anticipates that £27.1 million of the unrealised net losses on these derivative instruments in other comprehensive income will reverse during 2002/03 as the underlying contracts are settled.

A desired level of fixed rate debt is maintained through the use of interest rate and cross currency interest rate swaps. Foreign currency forward contracts are used to fix the exchange rate on future contracted purchases of assets. These transactions are accounted for as cash flow hedges. The group does not exclude any component of derivative gains and losses from the assessment of ineffectiveness. The amount of ineffectiveness for cash flow hedges recorded for the year ended 31 March 2002 was a loss of £0.1 million. Net realised losses on cash flow hedges totalling £6.3 million were transferred from accumulated other comprehensive income into income during the year to match the underlying hedged items recognised in the income statement. The group estimates that losses of £6.9 million on cash flow hedges in place at the year end will be transferred from accumulated other comprehensive income into income during 2002/03.

Net investment hedges

The group uses foreign currency forwards and cross currency swaps to protect the value of its investments in operations denominated in foreign currencies. The group excludes the spot-forward difference from the assessment of hedge effectiveness. In the year ended 31 March 2002 the group recorded a £2.4 million translation adjustment gain related to net investment hedges.

Recent US accounting pronouncements

In June 2001, the FASB issued FAS 141, ‘Business Combinations’. FAS 141 requires that the purchase method of accounting be used for all business combinations initiated after 30 June 2001, provides specific criteria for the initial recognition and measurement of intangible assets apart from goodwill and requires that unamortised negative goodwill be written off immediately as an extraordinary gain instead of being deferred and amortised. This statement supersedes APB No. 16 ‘Business Combinations’. There have been no material acquisitions in the current year and hence the adoption of this standard has had no material effect in the current year.

In June 2001, the FASB issued FAS 142, ‘Goodwill and Other Intangible Assets’ which became effective for the group on 1 April 2002. This statement addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes APB Opinion No.17, ‘Intangible Assets’. FAS 142 specifically states that it does not change the accounting prescribed by FAS 71, ‘Accounting for the Effects of Certain Types of Regulation’. FAS 142 prohibits the amortisation of goodwill and requires that goodwill be tested annually for impairment (and in interim periods if certain events occur which indicate that the carrying value of goodwill may be impaired). Goodwill amortisation charged to the profit and loss account under US GAAP for the year ended 31 March 2002 was £172.5 million. The group is currently evaluating the overall impact of adopting this statement on its results and financial position under US GAAP.

In June 2001, the FASB issued FAS 143, ‘Accounting for Asset Retirement Obligations’ which will be effective for the group beginning 1 April 2003. The statement requires the fair value of an asset retirement obligation to be recorded as a liability in the period in which the obligation was incurred. At the same time the liability is recorded, the costs of the asset retirement obligation will be recorded as an addition to the carrying amount of the related asset. Over time, the liability is accreted to its present value and the addition to the carrying amo      unt of the asset is depreciated over the asset’s useful life. Upon retirement of the asset, the group will settle the retirement obligation against the recorded balance of the liability. Any difference in the final retirement obligation cost and the liability will result in either a gain or loss. The group is currently evaluating the impact of adopting this statement on its results and financial position under US GAAP.

In August 2001, the FASB issued FAS 144, ‘Accounting for the Impairment or Disposal of Long-Lived Assets’ which supercedes FAS 121 ‘Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to be disposed of’. The group adopted FAS 144 in February 2002 effective from 1 April 2001. FAS 144 modifies and expands the financial accounting and reporting for the impairment or disposal of long-lived assets other than goodwill. The adoption of FAS 144 did not have a material effect on the group’s results and financial position under US GAAP.

In April 2002, the FASB issued FAS 145, ‘Recission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections’. FAS 145 will be effective for the group beginning 1 April 2003. This statement is not expected to have a material impact on the group’s results and financial position under US GAAP.

In 2001 the Derivatives Implementation Group issued guidance under Issue C16 ‘Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option Contract’. The guidance disallows normal purchases and normal sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. As a result, these contracts will be required to be marked-to-market through earnings. Issue C16 became effective for the group on 1 April 2002. The group is currently reviewing its contracts to determine which contracts, if any, will no longer qualify as normal purchase and normal sales contracts.

107

COMPANY BALANCE SHEET

as at 31 March 2002

	Notes	2002 £m		2001 £m
Fixed assets
Investments	35	4,769.4		4,746.4
Current assets
Debtors	36	141.0		718.8
Creditors: amounts falling due within one year
Loans and other borrowings	37	(266.3	)	—
Other creditors	38	(137.3	)	(166.6	)
		(403.6	)	(166.6	)
Net current (liabilities)/assets		(262.6	)	552.2
Net assets		4,506.8		5,298.6
Called up share capital	39	926.3		924.5
Share premium	39	2,254.1		3,739.7
Capital redemption reserve	39	18.3		18.3
Profit and loss account	39	1,308.1		616.1
Equity shareholders’ funds	39	4,506.8		5,298.6

Approved by the Board on 1 May 2002 and signed on its behalf by

Charles Miller Smith	David Nish
Chairman	Finance Director

The Accounting Policies and Definitions on pages 56 to 60, together with the Notes on pages 65 to 70, 72 to 74, 76 to 107 and 109 to 110 form part of these Accounts.

108

NOTES TO THE COMPANY BALANCE SHEET

as at 31 March 2002

35    Fixed asset investments

	Subsidiary undertakings				Own shares held under
	Shares £m		Loans £m		trust £m		Total £m
Cost or valuation:
At 1 April 2001	1,667.1		3,049.9		29.4		4,746.4
Additions	962.8		—		19.4		982.2
Demerger of Thus	(396.3	)	—		—		(396.3	)
Disposals and other	—		(558.6	)	(4.3	)	(562.9	)
At 31 March 2002	2,233.6		2,491.3		44.5		4,769.4

36    Debtors

	2002 £m	2001 £m
Amounts falling due within one year:
Loans to subsidiary undertakings	140.2	633.8
Interest due from subsidiary undertakings	0.8	85.0
	141.0	718.8

37    Loans and other borrowings due within one year

	2002 £m	2001 £m
Loans from subsidiary undertakings	166.3	—
Committed bank loans	100.0	—
	266.3	—

38    Other creditors

	2002 £m	2001 £m
Amounts falling due within one year:
Corporation tax	—	31.7
Accrued expenses	11.2	15.5
Proposed dividend	126.1	119.4
	137.3	166.6

39    Analysis of movements in shareholders’ funds

	Note		Number of shares 000s	Share capital £m	Share premium £m		Capital redemption reserve £m	Profit and loss account £m		Total £m
At 1 April 2001			1,849,026	924.5	3,739.7		18.3	616.1		5,298.6
Retained loss for the year			—	—	—		—	(808.0	)	(808.0	)
Share capital issued
—Employee sharesave scheme			99	0.1	0.5		—	—		0.6
—Executive share option scheme			78	—	0.2		—	—		0.2
—ESOP			3,444	1.7	13.7		—	—		15.4
Reduction of share premium	(a	)	—	—	(1,500.0	)	—	1,500.0		—
At 31 March 2002			1,852,647	926.3	2,254.1		18.3	1,308.1		4,506.8

(a) The company applied to the Court of Session (‘the Court’) to approve a reduction in the share premium account which had previously been approved by the company’s shareholders at an Extraordinary General Meeting on 21 January 2002. On 5 March 2002, the Court approved the reduction of the company’s share premium account by £1,500 million. This amount has been transferred to the company’s profit and loss account reserve. The reduction in the share premium account created sufficient distributable reserves to facilitate payment of a dividend in specie to demerge Thus.

40 Profit and loss account

As permitted by Section 230 of the Companies Act 1985, the company has not presented its own profit and loss account. The company’s profit and loss account was approved by the Board on 1 May 2002. The profit for the financial year per the Accounts of the company was £91.8 million (2001 £512.3 million). The retained loss for the year of £808.0 million is stated after cash dividends of £503.5 million and a dividend in specie on the demerger of Thus of £396.3 million.

109

Principal Subsidiary Undertakings and Other Investments

Subsidiary undertakings	Class of share capital	Proportion of shares held		Activity
Core Utility Solutions Limited	‘A’ Ordinary shares £1*	100	%	Multi-utility design and construction service
CRE Energy Limited	Ordinary shares £1	100	%	Wind-powered electricity generation
NA General Partnership**	n/a	100	%	Investment holding
PacifiCorp (USA)	Common stock	100	%	Regional electricity company
PacifiCorp Financial Services, Inc. (USA)	Common stock	100	%	Finance company
PacifiCorp Group Holdings Company (USA)	Common stock	100	%	Investment holding
PacifiCorp Holdings, Inc. (USA)	Common stock	100	%	US holding company
PacifiCorp Power Marketing, Inc. (USA)	Common stock	100	%	Wholesale power marketer, developer of wind-power projects and provider of natural gas/hub services
ScottishPower Energy Retail Limited	Ordinary shares £1	100	%	Supply of electricity and gas to domestic and business customers
ScottishPower Energy Trading Limited	Ordinary shares £1	100	%	Wholesale trading company engaged in purchase and sale of electricity, gas and coal
ScottishPower Energy Trading (Agency) Limited	Ordinary shares £1	100	%	Agent for trading activity of ScottishPower Energy Trading Limited and Scottish Power UK plc
ScottishPower Insurance Limited (Isle of Man)	Ordinary shares £1	100	%	Insurance
Scottish Power Generation Limited	Ordinary shares £1	100	%	Electricity generation
Scottish Power UK plc***	Ordinary shares 50p	100	%	Holding company
SP Dataserve Limited	Ordinary shares £1	100	%	Data collection, data aggregation, meter operation and revenue protection
SP Distribution Limited	Ordinary shares £1	100	%	Ownership and operation of distribution network within the ScottishPower area
SP Manweb plc	Ordinary shares 50p	100	%	Ownership and operation of distribution network within the Mersey and North Wales area
SP Power Systems Limited	Ordinary shares £1	100	%	Provision of asset management services
SP Transmission Limited	Ordinary shares £1	100	%	Ownership and operation of transmission network within the ScottishPower area
Southern Water Services Finance plc****	Ordinary shares £1	100	%	Finance company
Southern Water Services Limited****	Ordinary shares£1	100	%	Water supply and wastewater services
Fixed asset investments
Joint ventures
CeltPower Limited	Ordinary shares £1	50	%	Wind-powered electricity generation
N.E.S.T. Makers Limited	Ordinary shares £1	50	%	Energy efficiency agent for the ‘fuel poor’/benefit market
ScotAsh Limited	Ordinary shares £1	50	%	Sales of ash and ash-related cementitious products
Scottish Electricity Settlements Limited	Ordinary shares £1	50	%	Scottish electricity settlements
Shoreham Operations Company Limited	Ordinary shares £1	50	%	Management services
South Coast Power Limited	Ordinary shares £1	50	%	Electricity generation
Associated undertaking
Wind Resources Limited	Ordinary shares £1	45	%	Wind-powered electricity generation
Other investments
Folkestone & Dover Water Services Limited****	Ordinary shares £1	25	%	Water supply
	Preference shares £1	22	%
	Deferred shares£1	12	%

Notes

* Represents 50% of the total issued share capital.

** NA General Partnership is a partnership and therefore has no defined class of share capital.

*** The investment in this company is a direct holding of Scottish Power plc.

**** These investments were disposed of as a result of the sale of Southern Water on 23 April 2002.

The directors consider that to give full particulars of all undertakings would lead to a statement of excessive length. The information above includes the undertakings whose results or financial position, in the opinion of the directors, principally affect the results or financial position of the group.

All companies are incorporated in Great Britain, unless otherwise stated.

110

INDEPENDENT AUDITORS’ REPORT

to the members of Scottish Power plc

We have audited the Accounts which comprise the Accounting Policies and Definitions, the Group Profit and Loss Accounts, the Statement of Total Recognised Gains and Losses, the Note of Historical Cost Profits and Losses, the Reconciliation of Movements in Shareholders’ Funds, the Group Cash Flow Statement, the Reconciliation of Net Cash Flow to Movement in Net Debt, the Group Balance Sheet, the statement of Principal Subsidiary Undertakings and Other Investments, the Company Balance Sheet and the related notes.

Respective responsibilities of directors and auditors

The directors’ responsibilities for preparing the Annual Report and Accounts/Form 20-F in accordance with applicable United Kingdom law and accounting standards are set out in the statement of directors’ responsibilities.

Our responsibility is to audit the Accounts in accordance with relevant legal and regulatory requirements, United Kingdom Auditing Standards issued by the Auditing Practices Board and the Listing Rules of the Financial Services Authority.

We report to you our opinion as to whether the Accounts give a true and fair view and are properly prepared in accordance with the Companies Act 1985. We also report to you if, in our opinion, the Report of the Directors is not consistent with the Accounts, if the company has not kept proper accounting records, if we have not received all the information and explanations we require for our audit, or if information specified by law or the Listing Rules regarding directors’ remuneration and transactions is not disclosed.

We read the Chairman’s Statement, the Chief Executive’s Review, the Business Review, the Financial Review, the Corporate Governance statement, the Remuneration Report of the Directors and the other information contained in the Annual Report and Accounts/Form 20-F and consider the implications for our report if we become aware of any apparent misstatements or material inconsistencies with the Accounts.

We review whether the Corporate Governance statement reflects the company’s compliance with the seven provisions of the Combined Code specified for our review by the Listing Rules, and we report if it does not. We are not required to consider whether the board’s statements on internal control cover all risks and controls, or to form an opinion on the effectiveness of the company’s or group’s corporate governance procedures or its risk and control procedures.

Basis of audit opinion

We conducted our audit in accordance with Auditing Standards issued by the United Kingdom Auditing Practices Board and with Auditing Standards generally accepted in the United States. An audit includes examination, on a test basis, of evidence relevant to the amounts and disclosures in the Accounts. It also includes an assessment of the significant estimates and judgements made by the directors in the preparation of the Accounts, and of whether the accounting policies are appropriate to the group’s circumstances, consistently applied and adequately disclosed.

We planned and performed our audit so as to obtain all the information and explanations which we considered necessary in order to provide us with sufficient evidence to give reasonable assurance that the Accounts are free from material misstatement, whether caused by fraud or other irregularity or error. In forming our opinion we also evaluated the overall adequacy of the presentation of information in the Accounts.

United Kingdom opinion

In our opinion the Accounts give a true and fair view of the state of affairs of the company and the group at 31 March 2002 and of the loss and cash flows of the group for the year then ended and have been properly prepared in accordance with the United Kingdom Companies Act 1985.

United States opinion

In our opinion the Accounts referred to above present fairly, in all material respects, the consolidated financial position of the group at 31 March 2002 and 31 March 2001, and the results of its operations and its cash flows for the years ended 31 March 2002, 31 March 2001 and 31 March 2000 in conformity with accounting principles generally accepted in the United Kingdom. These principles differ in certain respects from accounting principles generally accepted in the United States. The effect of the differences in the determination of net loss/income, shareholders’ equity and cash flows is shown in Note 34 to the Accounts.

PricewaterhouseCoopers

Chartered Accountants and

Registered Auditors

Glasgow

1 May 2002

111

Five Year Summary

	Years ended 31 March
	Notes		2002 $ m			2002 £m			2001 £m			2000 £m			1999 £m			1998 £m
UK GAAP Information
Profit and Loss Account Information:
Turnover
—continuing operations	(a	)		7,843			5,523			5,410			3,110			2,334			2,319
—discontinued operations				1,123			791			939			1,005			908			809
Total turnover				8,966			6,314			6,349			4,115			3,242			3,128
Operating profit
—continuing operations	(a	)		903			636			569			395			527			532
—discontinued operations				200			141			153			267			276			253
Total operating profit				1,103			777			722			662			803			785
Operating profit (as adjusted)	(b)
—continuing operations	(a)			1,137			801			815			676			527			532
—discontinued operations				203			143			155			285			277			253
Total operating profit (as adjusted)				1,340			944			970			961			804			785
(Loss)/profit before taxation				(1,333	)		(939	)		380			1,149			644			640
Profit before taxation (as adjusted)	(b)			805			567			628			736			645			640
(Loss)/profit after taxation				(1,451	)		(1,022	)		285			886			469			460
(Loss)/profit for financial year	(c)			(1,401	)		(987	)		308			885			469			142
Cash dividends				(714	)		(503	)		(477	)		(341	)		(268	)		(243	)
Dividend in specie on demerger of Thus				(621	)		(437	)		—			—			—			—
Balance Sheet Information:
Total assets				23,167			16,315			16,976			15,516			6,232			5,577
Capital expenditure (net)	(d)			1,745			1,229			1,095			887			754			657
Long-term liabilities				11,811			8,318			7,793			6,895			2,852			2,145
Net debt				8,815			6,208			5,285			4,842			2,421			1,953
Equity shareholders’ funds				6,718			4,731			5,893			5,563			1,203			998
Net assets				6,842			4,818			6,179			5,863			1,204			1,000
Basic weighted average share capital (number of shares, million)				1,838			1,838			1,830			1,390			1,185			1,180
Diluted weighted average share capital (number of shares, million)				1,840			1,840			1,837			1,399			1,197			1,192
Ratios and statistics:
(Loss)/earnings per ordinary share			$	(0.7627	)		(53.71	)p		16.80	p		63.69	p		39.60	p		12.03	p
Earnings per ordinary share (as adjusted)	(f)		$	0.3709			26.12	p		27.86	p		37.97	p		39.70	p		38.90	p
Diluted (loss)/earnings per ordinary share			$	(0.7617	)		(53.64	)p		16.74	p		63.25	p		39.20	p		11.91	p
(Loss)/earnings per ScottishPower ADS	(e)		$	(3.05	)	£	(2.15	)	£	0.67		£	2.55		£	1.58		£	0.48
Earnings per ScottishPower ADS (as adjusted)	(e),(f)		$	1.48		£	1.04		£	1.11		£	1.52		£	1.59		£	1.56
Diluted (loss)/earnings per ScottishPower ADS	(e)		$	(3.05	)	£	(2.15	)	£	0.67		£	2.53		£	1.57		£	0.48
Cash dividends per ScottishPower ordinary share			$	0.3882			27.34	p		26.04	p		24.80	p		22.50	p		20.40	p
Cash dividends per ScottishPower ADS	(e)		$	1.57		£	1.09		£	1.04		£	0.99		£	0.90		£	0.82
Dividend cover (as adjusted)	(f)			1.0	x		1.0	x		1.1	x		1.5	x		1.8	x		1.9	x
Interest cover (as adjusted)	(f)			2.5	x		2.5	x		3.0	x		4.2	x		5.0	x		5.3	x
Gearing	(g)			131	%		131	%		90	%		87	%		201	%		196	%
US GAAP Information
Turnover
—continuing operations	(a)			7,843			5,523			5,410			3,110			2,334			2,319
—discontinued operations				1,123			791			939			1,005			908			809
Total turnover				8,966			6,314			6,349			4,115			3,242			3,128
(Loss)/profit for the financial year	(c)			(1,260	)		(887	)		387			870			451			126
(Loss)/earnings per ordinary share	(h)		$	(0.6853	)		(48.26	)p		21.13	p		62.59	p		38.08	p		10.70	p
Diluted (loss)/earnings per ordinary share			$	(0.6853	)		(48.26	)p		21.05	p		62.16	p		37.70	p		10.59	p
(Loss)/earnings per ScottishPower ADS	(e)(h)		$	(2.74	)	£	(1.93	)	£	0.85		£	2.50		£	1.52		£	0.43
Diluted (loss)/earnings per ScottishPower ADS	(e)		$	(2.74	)	£	(1.93	)	£	0.84		£	2.49		£	1.51		£	0.42
Total assets				25,302			17,818			18,646			16,971			7,344			6,695
Equity shareholders’ funds under US GAAP				8,307			5,850			7,463			7,001			2,457			2,249

(a) The results for the financial year ended 31 March 2000 included turnover of £711.7 million, operating profit of £114.9 million and operating profit, before goodwill amortisation, of £151.7 million in respect of PacifiCorp for the period of the year following its acquisition on 29 November 1999.

(b) Operating profit (as adjusted) and profit before taxation (as adjusted) exclude the effect of exceptional items and goodwill amortisation.

(c) Profit for the financial year ended 31 March 1998 is stated after charging windfall tax of £317 million.

(d) Capital expenditure is stated net of capital grants and customer contributions.

(e) (Loss)/earnings and cash dividends per ScottishPower ADS have been calculated based on a ratio of four ScottishPower ordinary shares to one ScottishPower ADS. Cash dividends per ScottishPower ADS are shown based on the actual amounts in US dollars

(f) The adjusted figures for Earnings per ordinary share, Earnings per ScottishPower ADS, Dividend cover and Interest cover exclude the effects of exceptional items, goodwill amortisation and windfall tax as applicable.

(g) Gearing is calculated by dividing net debt by equity shareholders’ funds.

(h) As permitted under UK GAAP, (loss)/earnings per share have been presented including and excluding the impact of the exceptional items, goodwill amortisation and windfall tax to provide an additional measure of underlying performance. In accordance with US GAAP, (loss)/earnings per share have been presented based on US GAAP earnings, without adjustments for the impact of UK GAAP exceptional items, goodwill amortisation and windfall tax. Such additional measures of underlying performance are not permitted under US GAAP.

(i) Amounts for the financial year ended 31 March 2002 have been translated, solely for the convenience of the reader, at $1.42 to £1.00, the closing exchange rate on 31 March 2002.

104

Glossary of Financial Terms and US Equivalents

UK Financial Terms used in the Annual Report & Accounts	US equivalent or definition
Accounts	Financial statements
Associates	Equity investees
Capital allowances	Tax depreciation
Capital redemption reserve	Other additional capital
Creditors	Accounts payable and accrued liabilities
Creditors: amounts falling due within one year	Current liabilities
Creditors: amounts falling due after more than one year	Long-term liabilities
Employee share schemes	Employee stock benefit plans
Employee costs	Payroll costs
Finance lease	Capital lease
Financial year	Fiscal year
Fixed asset investments	Non-current investments
Freehold	Ownership with absolute rights in perpetuity
Gearing	Leverage
Investment in associates and joint ventures	Securities of equity investees
Loans to associates and joint ventures	Indebtedness of equity investees not current
Net asset value	Book value
Operating profit	Net operating income
Other debtors	Other current assets
Own work capitalised	Costs of group’s employees engaged in the construction of plant and equipment for internal use
Profit	Income
Profit and loss account (statement)	Income statement
Profit and loss account (in the balance sheet)	Retained earnings
(Loss)/profit for financial year	Net (loss)/income
Profit on sale of fixed assets	Gain on disposal of non-current assets
Provision for doubtful debts	Allowance for bad and doubtful accounts receivable
Provisions	Long-term liabilities other than debt and specific accounts payable
Recognised gains and losses (statement)	Comprehensive income
Reserves	Shareholders’ equity other than paid-up capital
Severance costs	Early release scheme expenses
Share premium account	Additional paid-in capital or paid-in surplus (not distributable)
Shareholders’ funds	Shareholders’ equity
Stocks	Inventories
Tangible fixed assets	Property, plant and equipment
Trade debtors	Accounts receivable (net)
Turnover	Revenues

113

INVESTOR INFORMATION

Nature of trading market

The principal trading market for the ordinary shares of ScottishPower is the London Stock Exchange. In addition, American Depositary Shares (“ADSs”) (each of which represents four ordinary shares) have been issued by JPMorgan Chase Bank, as depositary (the “Depositary”), for the company’s ADSs and are traded on the New York Stock Exchange following listing on 8 September 1997.

Table 30 sets out, for the periods indicated, the highest and lowest middle market quotations for the ordinary shares, as derived from the Daily Official List of the London Stock Exchange and the range of high and low closing sale prices for ADSs, as reported on the New York Exchange Composite Tape.

Table 30—Historical share prices

	Ordinary shares1		American Depositary Shares2
Period	High (p)	Low (p)	High ($)	Low ($)
1997/98	582.00	352.00	38.74	23.18
1998/99	675.00	521.00	44.63	34.13
1999/00	601.50	359.50	39.11	22.97
2000/01
First quarter	576.00	498.00	33.88	33.44
Second quarter	576.00	495.00	30.69	29.88
Third quarter	567.00	483.50	30.75	30.06
Fourth quarter	529.00	422.00	26.65	26.15
2001/02
First quarter	521.84	430.64	30.24	24.90
Second quarter	513.06	351.14	29.66	20.90
Third quarter	412.59	355.78	24.51	21.05
Fourth quarter	426.49	350.00	24.75	20.10
October 2001	398.94	377.48	23.65	22.35
November 2001	412.59	372.60	24.51	22.14
December 2001	381.38	355.78	22.38	21.05
January 2002	418.45	370.65	24.29	21.99
February 2002	426.49	409.67	24.75	23.75
March 2002	406.74	350.00	23.80	20.10

Notes:

1 The past performance of the ordinary shares is not necessarily indicative of future performance.

2 Calculated using a ratio of four ordinary shares to one ADS, the ratio which took effect on the listing of the ADSs on the New York Stock Exchange on 8 September 1997. Until that time, each ADS represented 10 ordinary shares.

On 31 March 2002, there were 516 registered holders of 306,800 ordinary shares with addresses in the US and 66,234 registered holders of 71,774,628 ADSs (equivalent to 287,098,512 ordinary shares). The combined holdings of these shareholders represented 15.51% of the total number of ordinary shares outstanding as at 31 March 2002. UK registered shareholders held 84.10% of the total number of ordinary shares, and all shareholders other than those registered in the UK or the US held 0.39% of the total number of ordinary shares outstanding as at 31 March 2002. As certain of the ordinary shares and ADSs are held by brokers and other nominees, these numbers may not be representative of the actual number of beneficial owners in the US or elsewhere or the number of ordinary shares or ADSs beneficially held by US persons.

Table 31—Analysis of Ordinary Shareholdings at 31 March 2002

Range of holdings	No. of shareholdings	No. of shares
1-100	17,902	719,649
101-200	180,363	29,853,325
201-600	183,885	56,171,701
601-1,000	40,836	31,890,040
1,001-5,000	49,640	92,046,923
5,001-100,000	4,229	61,954,351
100,001 and above	773	1,580,010,995
Total	477,628	1,852,646,984

Share capital and options

As a result of the exercise of options under the Executive Share Option Scheme and the PacifiCorp Stock Incentive Plan and the issue of shares to the Trustee of the Employee Share Ownership Plan, a total of 3,621,192 ordinary shares of 50p each were issued during the year. Accordingly, the number of ordinary shares in issue was 1,852,646,984 as at 31 March 2002. During the year, 4,378,366 options over ordinary shares were granted to 3,902 employees under the ScottishPower Sharesave Scheme. A total of 2,353,775 options were granted under the Executive Share Option Plan 2001, which was introduced during the year. No options were granted under the Executive Share Option Scheme, which was replaced in 1996 by the introduction of the Long Term Incentive Plan. Awards in respect of 1,291,333 shares were made under the Plan during the year and these awards are subject to the achievement of specified performance criteria. Details are contained in the Remuneration Report. During the year ended 31 March 2002, options were granted to 121 employees under the PacifiCorp Stock Incentive Plan over a total of 3,547,600 ordinary shares.

Between 31 March 2002 and 1 May 2002, a further 340,044 ordinary shares have been issued as a result of the allotments in respect of the Employee Share Ownership Plan and of the exercise of options under the aforementioned share option schemes. At the Annual General Meeting of the

114

company last year, shareholders granted authority to the directors to purchase up to 184,930,589 ordinary shares. The directors have not exercised this authority.

Substantial shareholdings

As at 1 May 2002, the company had been notified that the following companies were substantial shareholders:

Capital Research and Management Company	5.83	%
Putnam Investment Management	3.30	%

Control of company

As far as is known to the company, it is not directly or indirectly owned or controlled by another corporation or by any foreign government.

As at 1 May 2002, no person known to the company, other than as shown above, owned more than 5% of any class of the group’s voting securities.

As at 1 May 2002, the total amount of voting securities owned by directors and executive officers of ScottishPower as a group is shown in Table 32 below.

Table 32—Voting securities

Title of Class Identity of Group	Amount Owned	Percentage of Class
Ordinary shares
Directors and officers (19 persons)	378,395	0.02	%

Full details of the directors’ interests in ScottishPower shares are shown in Tables 28 and 29 in the Remuneration Report.

None of the officers had a beneficial interest in 1% or more of the issued share capital.

In addition, as at 1 May 2002, the directors and officers of the company, as a group, held options to purchase 2,685,192 ordinary shares, all of which were issued pursuant to the Long Term Incentive Plan, Executive Share Option Scheme, Executive Share Option Plan 2001, ScottishPower’s Sharesave Schemes, Deferred Share Plan or the PacifiCorp Stock Incentive Plan.

The company does not know of any arrangements the operation of which might result in a change in control of the group.

Exchange rates

The group publishes its consolidated Accounts in pounds sterling. In this document, references to “pounds sterling”, “pounds”, “pence” or “p” are to UK currency and references to “US dollars”, “US$” or “$” are to US currency. Solely for the convenience of the reader, this report contains translations of certain pounds sterling amounts into US dollars at specified rates, or, if not so specified, at the Noon Buying Rate in New York City for cable transfers in pounds sterling as certified for customs purposes by the Federal Reserve Bank of New York (“Noon Buying Rate”) on 31 March 2002 of £1.00 = $1.42. On 1 May 2002, the Noon Buying Rate was $1.46 to £1.00. No representation is made that the pound sterling amounts have been, could have been or could be converted into US dollars at the rates indicated or at any other rates.

Table 33 sets out, for the periods indicated, certain information concerning the Noon Buying Rate for US dollars per £1.00.

Table 33—Historical exchange rates

Period	High		Low		Average1		Year end
1997/98	$	1.69	$	1.61	$	1.65	$	1.68
1998/99	$	1.72	$	1.60	$	1.65	$	1.61
1999/00	$	1.68	$	1.55	$	1.61	$	1.59
2000/01	$	1.61	$	1.40	$	1.52	$	1.42
2001/02	$	1.48	$	1.37	$	1.43	$	1.42
October 2001	$	1.48	$	1.42	$	1.45
November 2001	$	1.46	$	1.41	$	1.43
December 2001	$	1.46	$	1.42	$	1.45
January 2002	$	1.45	$	1.41	$	1.41
February 2002	$	1.43	$	1.41	$	1.41
March 2002	$	1.43	$	1.41	$	1.42

Note:

1 The average of the Noon Buying Rates on the last day of each month during the relevant period.

Dividends

Although dividends were historically declared and paid and financial reports published semi-annually, following completion of the merger with PacifiCorp, the company moved to quarterly reporting and the quarterly payment of dividends.

A dividend of 6.835 pence per share on the ordinary shares will be paid on 14 June 2002 to shareholders on the register on 10 May 2002. This makes total dividends for the year of 27.34 pence per share. A dividend of $0.3972 per ADS will also be paid on 14 June 2002 to ADS holders of record on 10 May 2002. This makes total dividends for the year of $1.5721 per ADS.

On 19 March 2002, the company completed the demerger of its interest in Thus Group plc (“Thus”). As a result of the demerger, and the subsequent conversion of Thus participating preference shares into Thus ordinary shares, ScottishPower shareholders received a special dividend on Thus ordinary shares of approximately 53.76 for every 100 ScottishPower ordinary shares held at 5.00pm on 15 March 2002, subject to the deduction of fractional entitlements arising from the demerger and subsequent conversion. The total value of this dividend as disclosed in the Group Profit and Loss Account was some £437 million.

The company remains committed to its stated aim of growing dividends by 5% per annum nominal for the period to March 2003.

Thereafter the Board intends to adopt a dividend policy which reflects both the reduced proportion of the ScottishPower group’s profits derived from UK regulated infrastructure businesses and the need to balance future investment with an appropriate dividend return for shareholders.

Accordingly, with effect from the year ending March 2004 the company intends to target dividend cover, based on earnings before goodwill amortisation and exceptional items, in the range 1.5-2.0 times, and ideally towards the middle of that range. ScottishPower will aim to grow dividends broadly in line with earnings thereafter.

Future dividends will be dependent upon the group’s earnings, financial condition and

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Table 34—Historical Dividend Payments

Pence per ordinary share	Notes 1	2001/02			2000/01			1999/00			1998/99			1997/98
Interim			—			—			8.27	p		7.50	p		6.80	p
Pre-completion			—			—			8.10	p		—			—
Quarter (29 Nov 1999 - 31 Dec 1999)			—			—			2.23	p		—			—
Quarter (1 Jan 2000 - 31 Mar 2000)			—			—			6.20	p		—			—
Quarter (1 April - 30 June)			6.835	p		6.51	p		—			—			—
Quarter (1 July - 30 Sept)			6.835	p		6.51	p		—			—			—
Quarter (1 Oct - 31 Dec)			6.835	p		6.51	p		—			—			—
Quarter (1 Jan - 31 Mar )			6.835	p		6.51	p		—			—			—
Final			—			—			—			15.00	p		13.60	p
Total			27.34	p		26.04	p		24.80	p		22.50	p		20.40	p
US dollars per ADS	1,2
Interim			—			—		$	0.5324		$	0.48		$	0.46
Pre-completion			—			—		$	0.5215			—			—
Quarter (29 Nov 1999 - 31 Dec 1999)			—			—		$	0.1413			—			—
Quarter (1 Jan 2000 - 31 Mar 2000)			—			—		$	0.3856			—			—
Quarter (1 April - 30 June)		$	0.3907		$	0.3928			—			—			—
Quarter (1 July - 30 Sept)		$	0.3979		$	0.3702			—			—			—
Quarter (1 Oct - 31 Dec)		$	0.3863		$	0.3805			—			—			—
Quarter (1 Jan - 31 Mar)		$	0.3972		$	0.3721			—			—			—
Final			—			—			—		$	0.97		$	0.91
Total		$	1.5721		$	1.5156		$	1.5808		$	1.45		$	1.37

Notes:

1 Dividends per share and per ADS are shown net of any associated UK tax credit available to certain holders of ordinary shares and ADSs. See “Taxation of Dividends”. Dividends paid by the Depositary in respect of ADSs are paid in US dollars based on a market rate of exchange that differs from the Noon Buying Rate.

2 Calculated based on a ratio of four ordinary shares for one ADS.

other factors. Dividends paid in the past are not necessarily indicative of future dividends.

Table 34 sets out the dividends paid on ordinary shares and ADSs in respect of the past five financial years, excluding any associated UK tax credit in respect of such dividends. A person resident in the UK for tax purposes who receives a dividend from the company is generally entitled to a tax credit, currently at a rate of 1/9th of the dividend (“associated UK tax credit”). For further information, see “Taxation of Dividends”.

Memorandum and Articles of Association

A summary of certain provisions of the company’s Memorandum and Articles of Association will be filed with the company’s report to the US Securities and Exchange Commission on Form 20-F.

Exchange controls and other limitations affecting security holders

There are currently no UK laws, decrees or regulations that restrict the export or import of capital, including, but not limited to, foreign exchange capital restrictions, or that affect the remittance of dividends or other payments to non-UK resident holders of the company’s securities except as otherwise set forth in “Taxation”.

There are no limitations imposed by UK law or by the company’s Memorandum and Articles of Association that restrict the right of non-UK resident or non-UK citizen owners to hold or to vote the ordinary shares.

Taxation

        The following discussion of UK tax and US federal income tax consequences is set forth with respect to US tax considerations in reliance upon the advice of Milbank, Tweed, Hadley & McCloy LLP, special US counsel to the company, and with respect to UK tax considerations in reliance upon the advice of Freshfields Bruckhaus Deringer, the company’s UK lawyers. The discussion is intended only as a summary of the principal US federal income tax and UK tax consequences to investors who hold the ADSs or ordinary shares as capital assets and does not purport to be a complete analysis or listing of all potential tax consequences of the purchase, ownership and disposition of ADSs or ordinary shares. The summary does not discuss special tax rules that may be applicable to certain classes of investors, including banks, insurance companies, tax exempt entities, dealers, traders who elect to mark to market, investors with a functional currency other than the US dollar, persons who hold ADSs as part of a hedge, straddle or conversion transaction, or holders of 10% or more of the voting stock of the company. The statements of UK and US tax laws and practices set out below are based on the laws in force and as interpreted by the relevant taxation authorities as of the date of this report. The statements are subject to any changes occurring after that date in UK or US law or practice, in the interpretation thereof by the relevant taxation authorities, or in any double taxation convention between the US and the UK. On July 24, 2001, the US and the UK signed a new convention between the two countries for the avoidance of double taxation with respect to taxes on income and capital gains. This new convention is not yet in force since it has not yet been ratified by the US and UK. The following discussion is based on the relevant provisions of the existing convention (“Income Tax Convention”). The company believes, and the discussion therefore assumes, that it is

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not a passive foreign investment company for US federal income tax purposes.

Each investor is urged to consult their own tax adviser regarding the tax consequences of the purchase, ownership and disposition of ordinary shares or ADSs under the laws of the US, the UK and their constituent jurisdictions and any other jurisdiction where the investor may be subject to tax.

If the obligations contemplated by the Deposit Agreement are performed in accordance with its terms, a beneficial owner of ADSs will be treated as the owner of the underlying ordinary shares for the purposes of the Income Tax Convention and the US Internal Revenue Code of 1986, as amended (“Code”).

For the purposes of this summary, the term “US Holder” means a beneficial owner of the ADSs that is a US citizen or resident, a domestic corporation or partnership, a trust subject to the control of a US person and the primary supervision of a US court, or an estate, the income of which is subject to US federal income tax regardless of its source.

For the purposes of this summary, the term “Eligible US Holder” means a US holder that is a resident of the US for the purposes of the Income Tax Convention and that satisfies the following conditions:

• is not also resident in the UK for UK tax purposes;

• is not a corporation which, alone or together with one or more associated corporations, controls, directly or indirectly, 10% or more of the voting stock of the company;

• whose holding of the ADSs is not attributable to a permanent establishment in the UK through which such holder carries on a business or with a fixed base in the UK from which such holder performs independent personal services; and

• under certain circumstances, is not a company 25% or more of the capital of which is owned, directly or indirectly, by persons that are neither individual residents of, nor nationals of the US.

Taxation of dividends

The company is not required to withhold any UK taxes from its dividend payments to US Holders. Therefore the amount of a dividend paid to a US Holder will not be reduced by any UK withholding tax. Under UK tax law and the Income Tax Convention, an Eligible US Holder is in theory entitled to an additional payment from the UK (“UK tax credit”) equal to  ¹/9th of the amount of any dividend paid by the company to the holder. While, as noted above, the dividend paid by the company is not subject to any UK withholding tax, under current UK law, the UK tax credit that otherwise would be payable by the UK is completely offset by a UK withholding tax equal to 100% of that UK tax credit. Accordingly, US Holders will receive the full amount of any dividend declared by the company (without deduction for UK tax) but will not be entitled to an additional cash payment from the UK in respect of the UK tax credit. An Eligible US Holder who elects to claim a credit (as described below) against the holder’s US federal income tax liability with respect to the UK withholding tax imposed on the UK tax credit amount, is required to include, in addition to the gross amount of the dividend paid by the company, the amount of UK tax credit in taxable income for US federal income tax purposes, even though none of the amount of the UK tax credit is paid by the UK. An Eligible US Holder who so elects to include the amount of the UK tax credit in taxable income, generally will be entitled to credit against the holder’s US tax liability, the amount of the UK tax credit that the holder is deemed to have received, which US tax credit may result in a reduction in the holder’s effective US tax rate on the cash dividend received. Following is a simplified numerical example of the US tax treatment of dividends paid to an Eligible US Holder who is subject to tax at a rate of 35% and is eligible for and claims a US tax credit for the complete amount of the UK tax credit:

	$
Dividend received	90.00
UK tax credit	10.00
US taxable income	100.00
US tax @ 35%	35.00
US tax credit for UK withholding tax	(10.00	)
US tax liability	25.00
Cash dividend received	90.00
US tax liability	(25.00	)
After-tax cash amount	65.00
Approximate effective US tax rate on cash received	27.8	%

Note that the US federal income tax consequences of dividends paid to an Eligible US Holder will depend upon the holder’s particular circumstances and, consequently, the US federal income tax consequences applicable to a particular holder may differ from those set out in the above example. Eligible US Holders are urged to consult their own tax advisers regarding the tax consequences to them of the payment of a dividend by the company.

The full procedures for determining and claiming a US tax credit, with respect to dividends received from a UK corporation, are outlined in US Internal Revenue Service Revenue Procedure 2000 - 13, 2000 - 6 I.R.B. 1.

A US Holder recognises income when the dividend is actually or constructively received by the holder, in the case of ordinary shares, or by the Depositary, in the case of ADSs. The dividend will not be eligible for the dividends received deduction generally allowed to US corporations in respect of dividends received from other US corporations. Distributions in excess of current and accumulated earnings and profits, as determined for US federal income tax purposes, will be treated as a return of capital to the extent of the Eligible US Holder’s basis in the ordinary shares or ADSs and thereafter as a capital gain. In determining the amount of the distribution, a US Holder will use the spot currency exchange rate on the date the dividend is included in income. Any difference between that amount and the dollars actually received may constitute a foreign currency gain or loss. However, individual Eligible US Holders are not required to recognise a gain of less than $200 from the exchange of foreign currency in a “personal transaction” as defined in Section 988(e) of the Code.

Subject to certain limitations and requirements, an Eligible US Holder will be entitled under the Income Tax Convention to credit the UK withholding tax imposed on the amount of the UK tax credit against the Eligible US Holder’s US federal income tax liability, provided the holder includes the gross amount of the UK tax credit in the holder’s gross income as described above. Claiming a US foreign tax credit with respect to the UK withholding tax imposed under the Income Tax Convention upon the UK tax credit, may result in a lower effective US

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federal income tax rate on dividends paid by the company for certain Eligible US Holders as demonstrated in the above numbered example. An Eligible US Holder is not required to affirmatively make a claim to the UK Inland Revenue to be entitled to the US foreign tax credit, although an Eligible US Holder electing to claim the credit must complete an Internal Revenue Service Form 8833 (Treaty Based Return Position Disclosure) and file such Form with the holder’s US federal income tax return. Eligible US Holders that include the amount of the UK tax credit in gross income, but do not elect to claim foreign tax credits may instead claim a deduction for UK withholding tax. For foreign tax credit limitation purposes, the dividend will be income from sources outside the US. The rules relating to the computation of foreign tax credits are complex and Eligible US Holders should consult their own tax advisers to determine whether, and to what extent, a credit would be available and whether any filings or other actions may be required to substantiate an Eligible US Holder’s foreign tax credit claim.

If the US Holder is a US partnership, trust or estate, the UK tax credit will be available only to the extent that the income derived by such partnership, trust or estate is subject to US federal income tax as the income of a resident either in its hands or in the hands of its partners or beneficiaries, as the case may be. Whether holders of ADSs who reside in countries other than the US are entitled to a tax credit in respect of dividends on ADSs depends in general upon the provisions of conventions or agreements, if any, as may exist between such countries and the UK.

Taxation of capital gains

In general, for US tax purposes, US Holders of ADSs will be treated as the owners of the underlying ordinary shares that are represented by such ADSs and deposits and withdrawals of ordinary shares by US Holders in exchange for ADSs will not be treated as a sale or other disposition for US federal income tax purposes. Upon a sale or other disposition of ordinary shares or ADSs, US Holders will recognise a gain or loss for US federal income tax purposes in an amount equal to the difference between the US dollar value of the amount realised and the US Holder’s tax basis (determined in US dollars) in such ordinary shares or ADSs. Generally, such gain or loss will be a long-term capital gain or loss if the US Holder’s holding period for such ordinary shares or ADSs exceeds one year. Any such gain or loss generally will be income from sources within the US for foreign tax credit limitation purposes. Long-term capital gain for an individual US Holder is generally subject to a maximum tax rate of 20%.

A US Holder who is not resident or ordinarily resident for UK tax purposes in the UK will not generally be liable for UK tax on capital gains recognised on the sale or other disposition of ADSs or ordinary shares, unless the ADS holder carries on a trade, profession or vocation in the UK through a branch or agency and the ADSs are, or have been, used, held or acquired for the purposes of such trade, profession or vocation or such branch or agency.

US citizens resident or ordinarily resident in the UK, US corporations resident in the UK by reason of their business being managed or controlled in the UK and US citizens who or US corporations which, are trading or carrying on a trade, profession or vocation in the UK through a branch or agency and who or which have used, held or acquired ADSs or ordinary shares for the purposes of such trade, profession or vocation or such branch or agency may be liable for both UK and US tax in respect of a gain on the disposal of the ADSs. Such holders may not be entitled to a tax credit against their US federal income tax liability for the amount of UK capital gains tax or UK corporation tax on chargeable gains, as the case may be, paid in respect of such gain unless the holder appropriately can apply the credit against tax due on income from foreign sources.

US information reporting and backup withholding

In general, information reporting requirements will apply to dividend payments (or other taxable distributions) in respect of ordinary shares or ADSs made within the US to a non-corporate US person. Accordingly, individual US Holders will receive an annual statement showing the amount of taxable dividends (or other reportable distributions) paid to them during the year. “Backup withholding” at the rate of 30% will apply to such payments (i) if the holder or beneficial owner fails to provide an accurate taxpayer identification number in the manner required by US law and applicable regulations, (ii) if there has been notification from the Internal Revenue Service of a failure by the holder or beneficial owner to report all interest or dividends required to be shown on its federal income tax returns or, (iii) in certain circumstances, if the holder or beneficial owner fails to comply with applicable certification requirements.

        In general, payment of the proceeds from the sale of ordinary shares or ADSs to or through a US office of a broker is subject to both US backup withholding and information reporting requirements, unless the holder or beneficial owner establishes an exemption. Different rules apply to payments made outside the US through an office outside the US.

UK inheritance tax

An individual who is domiciled in the US for the purposes of the convention between the US and the UK for the avoidance of double taxation with respect to estate and gift taxes (“Estate Tax Convention”) and who is not a national of the UK for the purposes of the Estate Tax Convention will not generally be subject to UK inheritance tax in respect of the ADSs or ordinary shares on the individual’s death or on a gift of the ADSs or ordinary shares during the individual’s lifetime, unless the ADSs or ordinary shares are part of the business property of a permanent establishment of the individual in the UK or pertain to a fixed base in the UK of an individual who performs independent personal services. Special rules apply to ADSs held in trust. In the exceptional case where the shares are subject both to UK inheritance tax and to US federal gift or estate tax, the Estate Tax Convention generally provides for the tax paid in the UK to be credited against tax paid in the US.

UK stamp duty and stamp duty reserve tax

In practice, no UK stamp duty need be paid on the acquisition or transfer of ADSs provided that the instrument of transfer is executed outside the UK and subsequently remains at all times outside the UK. An agreement to transfer ADSs will not give rise to a liability to stamp duty reserve tax.

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Subject to certain exceptions, a transfer on sale of ordinary shares, as opposed to ADSs will generally be subject to UK stamp duty at a rate of 0.5% (rounded up, if necessary, to the nearest £5) of the consideration given for the transfer. An agreement to transfer such shares will normally give rise to a charge to UK stamp duty reserve tax at a rate of 0.5% of the consideration payable for the transfer, provided that stamp duty reserve tax will not be payable if stamp duty has been paid. Where such ordinary shares are later transferred to the Depositary’s nominee, further stamp duty or stamp duty reserve tax will normally be payable at the rate of 1.5% (rounded up, if necessary, to the nearest £5) of the value of the ordinary shares at the time of the transfer.

A transfer of ordinary shares by the Depositary or its nominee to the relative ADS holder when the ADS holder is not transferring beneficial ownership gives rise to a UK stamp duty liability of £5 per transfer.

Taxation of Thus demerger dividend in specie

Information pertaining to the tax position of shareholders following the demerger of Thus can be obtained from the Company Secretary at the company’s registered office.

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Financial Calendar

14 June 2002	Dividend payment date – US and UK (final dividend for the year ended 31 March 2002)
25 July 2002	Announcement of results for quarter ending 30 June 2002—Q1
26 July 2002	Annual General Meeting
August 2002	Shares ex-dividend
September 2002	Q1 Dividend payable
November 2002	Announcement of results for quarter ending 30 September 2002—Q2
November 2002	Shares ex-dividend
December 2002	Q2 Dividend payable
February 2003	Announcement of results for quarter ending 31 December 2002—Q3
February 2003	Shares ex-dividend
March 2003	Q3 Dividend payable
May 2003	Announcement of Preliminary Results for the year ending 31 March 2003
May 2003	Shares ex-dividend
June 2003	Q4 Dividend payable (final dividend for the year ending 31 March 2003)

Annual General Meeting

The Annual General Meeting will be held at the Edinburgh Festival Theatre, 13/29 Nicolson Street, Edinburgh on Friday 26 July 2002 at 11.00 am. Details of the resolutions to be proposed at the Annual General Meeting are contained in the Notice of Meeting.

Quarterly results

Copies of the quarterly results may be obtained, free of charge, on request from the Company Secretary at the company’s registered office. Quarterly results will also be published on the company’s website: www.scottishpower.com

Half-year results

The company, as permitted by the London Stock Exchange, publishes its half-year results in one UK national newspaper. In 2002, it is expected that the half-year results will be published in The Times and on the company’s website. Copies of the half-year results may be obtained, free of charge, on request from the Company Secretary at the company’s registered office.

Environment and Community reports

Copies of the Corporate Environment Sustainability Report and the Community Report may be obtained, free of charge, on request from the Company Secretary at the company’s registered office. The Corporate Environment Sustainability Report, the Corporate Environment Performance Report and Community Report are published on the company’s website.

Press releases and up-to-date information on the company can be found on the company’s website.

The Annual Review 2001/02 is also available on audio tape, free of charge, from the Company Secretary at the company’s registered office.

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SHAREHOLDER SERVICES

Ordinary Shares

Share registration enquiries

The Registrar

Lloyds TSB Registrars Scotland PO Box 28448 Edinburgh EH4 1WQ

Tel:   Fax:  Textphone: +44 (0)870 600 3999 +44 (0)870 900 0030 +44 (0)870 600 3950

Website: www.shareview.co.uk

Dividend Reinvestment Plan

The Dividend Reinvestment Plan provides UK ordinary shareholders with the facility to invest cash dividends by purchasing further ScottishPower shares. For further details, please contact Lloyds TSB on telephone number 0870 241 3018.

Share consolidation and ISAs

Share consolidation is a facility which allows a number of holdings, and especially family holdings, to be consolidated into one holding. This service is provided free of charge.

Individual Savings Accounts (“ISAs”) are suitable for UK resident private investors who wish to shelter their ScottishPower shares from Income and Capital Gains Tax. Details of the ScottishPower ISA service are available from Lloyds TSB at the following address. Alternatively, please call the ISA helpline on 0870 242 4244.

Lloyds TSB Registrars ISAs

The Causeway

Worthing BN99 6UY

Share dealing

ScottishPower ordinary shares may be bought or sold at competitive rates by post or telephone. For further details, please contact Stocktrade on 0845 601 0979, quoting LOW C0070.

American Depositary Shares (“ADSs”)

Exchange and stock transfer enquiries

JPMorgan Chase Bank

Shareholder Relations

PO Box 43013

Providence, RI 02940-3013

Tel: 1 (866) SCOTADR (Toll Free)

1 (866) 726 8237 (Toll Free)

+1 (781) 575 2678 (Outside US not Toll Free)

Fax: +1 (781) 575 4082

Website: www.adr.com/shareholder

Dividend Reinvestment Plan Global Invest Direct

Global Invest Direct is the Direct Share Purchase and Dividend Reinvestment Plan for ADS holders which allows existing and first time investors to purchase ADSs without a broker. Global Invest Direct encourages investors to make initial and ongoing investments in the company by providing investors with the convenience of investing directly in ScottishPower’s ADSs, with reduced brokerage commissions and service costs. For further details, please contact JPMorgan Chase Bank as detailed above.

Agent for US federal securities laws

The agent for ScottishPower for US federal securities law purposes is:

Puglisi & Associates,

850 Library Avenue, Suite 204

PO Box 885

Newark

Delaware 19715

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Index

Accounting		Earnings and dividends		Pensions costs
developments	41	2001/02	33	accounting policy	59
policies and definitions	41-43, 56-60	2000/01	36	analysis	91-95 (29), 102 (34d)
Acquisition	34, 73(11,12),77(16)	Earnings per ordinary share	1,70(7)	Post-retirement benefits
American Depositary Shares	121	Employees		accounting policy	59
Annual General Meeting	120	numbers and costs	15,67(3)	analysis	94 ( 29h), 104 (34e)
Audit Committee	45,46	policies, UK and US	25	Profit and loss account
Audit Report	111	Environment		company	109(40)
Balance sheets		accounting policy	59	group	61-63
company	108	policy approach	9,16	Property	16
group	75	regulation	22-25	Provisions for liabilities
Board of Directors	44	Exceptional items	2,30,68(4)	and charges	86(23),87(24)
Borrowings	80-85 (21)	Executive Team	45,46	Recognised gains and losses	64
Business		Financial		Registrar	121
description of	10-17	commitments	37,95(31)	Regulation
reviews—2000/01	34-36	highlights	1	electricity and gas UK	20
reviews—2001/02	31-34	review	30-43	electricity US	18
strategy	3,10	Financial instruments		environmental UK	23
Capital commitments	95 (31b)	accounting policies	57	environmental US	22
Capital expenditure	33, 76 (14b)	analysis	80-85 (21)	Related party transactions	96(32)
Capital gains tax	118	Five Year Summary	112	Remuneration Committee
Cash flow		Fixed assets		membership	45,46,48
acquisitions and disposals	73(11,12)	intangible	77(16)	report	48-54
analysis	72(9)	investments	58,79(18),109(35)	Research and development	16,66(2)
commentary	33	tangible	58,78(17)	Reserves	90(27),109(39)
group statement	71	Glossary		Risk management	38-40, 46
US GAAP	102(34)	of financial terms	113	Segmental information	65(1),76(14)
Chairman’s Statement	2	of general terms	123	Share capital	87(26),109(39)
Charitable donations	16	Going concern	41	Share options	88 (26b), 114
Chief Executive’s Review	3-9	Goodwill		Share premium	90(27),109(39)
Contingent liabilities	95(30)	accounting policy	58	Shareholder services	121
Corporate governance	46	analysis	77(16)	Shareholders’ funds
Creditor payment policy and practice	40	Grants and contributions		analysis	90(27),109(39)
Creditors	85(22),109(38)	accounting policy	59	reconciliation	64
Currencies, accounting policy	59	analysis	87(25)	Shareholdings, analysis	114
Debt (net)		Health and safety	25	Southern Water	9,15
analysis	74(13)	Inheritance tax	118	Stocks
reconciliation to net cash flow	71	Interest charge (net)		accounting policy	59
Debtors	80(20),109(36)	accounting policy	57	analysis	79(19)
Deferred income	87(25)	analysis	69(5)	Substantial shareholdings	115
Deferred tax	69(6),87(24)	Interest and Taxation		Taxation
Depreciation		2000/01	36	accounting policy	58
accounting policy	58	2001/02	32	analysis	69(6)
by segment	65 (1c)	Internal control	46	commentary	32,36
Directors		Investor information	114-119	deferred	69(6),87(24)
executive	44	Leased assets, accounting policy	58	of dividends	116-119
non-executive	44	Litigation	26	Thus	9,15
pensions	50	Loans and other borrowings	80-85 (21)	Total assets by segment	76 (14c)
remuneration	48-54	Long Term Incentive Plan	49,52,53,59	Treasury	36
report	1-55	Minority interests	91(28)	Turnover
responsibilities for accounts	55	Net asset value per share	77(15)	accounting policy	57
service contracts	50	Net assets by segment	76 (14a)	by segment	65 (1a)
share options	49,52	Nomination Committee	45,46	highlights	1
shareholdings	52	Operating profit		US GAAP	97-107 (34)
Dividends		analysis	66(2)	US regulatory assets	59
in specie	33,70(8)	by segment	65 (1b)
per ADS	116	highlights	1	Figures in brackets refer to Notes to the Accounts
per ordinary share	3,70(8),116	reconciliation to net operating
payment dates	120	cash flows	73(10)
Divisions		Own shares held under trust	58
Infrastructure	7,14	PacifiCorp	3-5, 10-12, 18-20
UK	6,12	PacifiCorp Power Marketing, Inc.	5,12
US	3,10

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Glossary of Terms

Term—Definition

ADS—American Depositary Share (US)

The Authority—The Gas and Electricity Markets Authority, the body which determines energy market regulation in Great Britain (UK)

BE—British Energy plc (UK)

BETTA—British Electricity Trading and Transmission Arrangements (UK)

BPA—Bonneville Power Administration (US)

btu—British thermal unit (UK)

Billion—One thousand million (1,000,000,000)

Churn—The turnover of existing customers leaving, and new customers joining, the company’s customer list

CO₂—Carbon Dioxide

Combined Code—Guidelines setting out corporate governance principles regarded as good practice for UK registered companies (UK)

Company—Scottish Power plc

Competition Commission—The UK regulatory body concerned with competition policy and the abuse of market power (UK)

Demand side management—Encouraging customers to reduce their power consumption

Distribution—The transfer of electricity from the transmission system to customers (US equivalent is Power Distribution)

DTI—Department of Trade and Industry (UK)

EA—Environment Agency (UK)

EBITDA—Earnings before interest, tax, depreciation and amortisation

EU—European Union

EPA—Environmental Protection Agency (US)

EMFs—Electric and Magnetic Fields

Energy supply—Sales of electricity and gas to residential, commercial and industrial customers (UK)

ESOP—Employee Share Ownership Plan (UK)

ExSOP—Executive Share Option Scheme open to the company’s executive directors and senior managers

FERC—Federal Energy Regulatory Commission (US)

GAAP—Generally Accepted Accounting Principles

Gas—Natural gas

Giga (G)—One thousand million (1,000,000,000) units

Great Britain—England, Scotland and Wales

Group—Scottish Power plc and its consolidated subsidiaries

Guaranteed Standards—Standards of performance agreed between the company and Ofgem for transmission, distribution and supply (UK)

Home area—The geographical area in which a company was previously the sole licenced supplier of residential customers (UK)

Interconnectors—The high voltage links connecting the transmission system of Scotland with those of England & Wales and Northern Ireland (UK)

ISA—Individual Savings Account (UK)

Kilo (k)—One thousand (1,000) units

LTIP—Long Term Incentive Plan

Mega (M)—One million (1,000,000) units

MSP—The multi-state process through which PacifiCorp and the six states it serves are working to clarify roles and responsibilities concerning the regulation of PacifiCorps’ business activities (US)

NEA—Nuclear Energy Agreement, between British Energy, ScottishPower and Scottish & Southern (UK)

NETA—New Electricity Trading Arrangements (UK)

NOx—Oxides of Nitrogen

Ofgem—Office of Gas and Electricity Markets, the gas and electricity regulator in Great Britain (UK)

OFWAT—Office of Water Services, the water regulator in England & Wales (UK)

PED—Public Electricity Distributor (UK)

plc—Public limited company (UK)

Power production—The US term for the generation of electricity

PSCs—Public Services Commissions, the individual bodies which regulate utilities in each of the states (US)

Rates—The US term for Tariffs

Retail sales—Sales of electricity to residential, commercial and industrial customers (US)

ROSPA—Royal Society for the Prevention of Accidents (UK)

RPI—Retail Price Index, the equivalent of the US Consumer Price Index—CPI (UK)

SEC—Securities and Exchange Commission (US)

SEE—Social, environmental and ethical

SEPA—Scottish Environment Protection Agency (UK)

SO₂—Sulphur Dioxide

Tera (T)—Indicates a measure of 10¹², for example terawatthours

Transmission—The transfer of electricity from power stations to the distribution system

Transportation (of gas)—Transfer of gas from on-shore terminals to consumers through the national pipeline network (UK)

UK—United Kingdom, comprising England, Scotland, Wales and Northern Ireland

US—United States of America

Volt (V)—Unit of electrical potential

Watt (W)—Unit of electrical power, the rate at which electricity is produced or used

Watt hour (Wh)—Unit of electrical energy, the production or consumption of one Watt for one hour

WECC—Western Electricity Coordinating Council (US)

Wholesale—The dealing of bulk power with another power supplier

Windfarm—A group of wind-driven turbines intended to generate electricity

(US) or (UK) in the definitions above indicates that the term is applicable to the United States or the United Kingdom, respectively.

Conversion	Metres		Yards
Factors	0.91	1	1.09
	Km		Miles
	1.61	1	0.62
	Litres		US Gallons
	3.78	1	0.26

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