Document:

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                                                                    Exhibit 10.1

        Summary of Memorandum of Association and Articles of Association

                              of Scottish Power plc

         The following is a summary of certain provisions of the Memorandum of
Association and the Articles of Association of Scottish Power plc (the
"Company") required by Item 10(B) of Form 20-F under the United States
Securities Exchange Act of 1934.

Memorandum of Association

1)       Objects and Purposes. The Company's objects and purposes under its
Memorandum of Association are set forth in Article 4 and are to carry on the
business of a holding company, to generate, transmit, distribute and supply
electricity as well as any other form of energy, to carry on the business of a
water undertaker, to carry on the business of a sewerage undertaker, to run,
operate, manage, service, repair and deal in telecommunications, to carry on any
other trade or business which is for the benefit of the Company and to do
anything incidental or conducive to these objects anywhere in the world.

Articles of Association

2)       Directors.

(a)      A Director directly or indirectly interested in a proposed contract
with the Company or any subsidiary of the Company shall declare the nature of
his interest. A Director is prohibited from voting where he has any material
interest, unless it relates to his interests in shares, debentures or other
securities in the Company. However, a Director will be able to vote where the
resolution concerns any of the following:

         (i)   giving a guarantee, security or indemnity in respect of
               obligations incurred by him;

         (ii)  giving a guarantee, security or indemnity in respect of an
               obligation incurred by the Company for which he has assumed
               responsibility;

         (iii) a proposal to subscribe for or purchase shares, debentures or
               other securities of the Company following an offer to the public;

         (iv)  an offer for shares, debentures or other securities of the
               Company in which he may be interested as a participant in the
               underwriting;

         (v)   a contract relating to another company in which he does not hold
               an interest of 1% or more of the issued share capital or of the
               voting rights;

         (vi)  a contract for the benefit of employees which awards no extra
               benefit to the Director; and

         (vii) insurance which the Company is empowered to purchase and/or
               maintain for the benefit of the Directors.

(b)      Directors are prevented from voting in respect of contracts or
arrangements in which they have a material interest and as such will not be
counted in any quorum at such a meeting. In the absence of a quorum the
Directors present may only act either to fill vacancies in their number or to
summon general meetings.

(c)      Directors may exercise all borrowing powers of the Company.

(d)      There are no requirements for a Director to retire at a certain age.
The age of a Director who has attained the age of 70 must be stated in the
notice convening the general meeting at which he is proposed to be elected or
re-elected. At the Annual General Meeting every year, one-third of the Directors
subject to retirement by rotation shall retire.

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(e)      There is no share qualification for Directors.

3)       Share rights.

(a)      No dividend is payable except out of Company profits available for
distribution. All dividends are to be apportioned and paid pro rata according to
the amounts paid on the shares. The Company may pay dividends in specie either
on the recommendation of the Directors, by ordinary resolution or by resolution
of the Directors. All moneys that are unclaimed may be invested or put to use by
the Directors for the benefit of the Company until claimed. Any dividend that is
unclaimed for 12 years from the date when it fell due for payment may be
forfeited and shall revert to the Company.

(b)      Every member present in person and entitled to vote on a show of hands
shall have one vote. On a poll, every member present in person and entitled to
vote shall have one vote for every share held.

(c)      Directors are elected for staggered terms.

(d)      A liquidator may, with the authority of an extraordinary resolution,
divide among the members the whole, or any part of, the assets of the Company.

(e)      The Company has no redeemable shares outstanding, but may issue shares
that may be redeemed at the option of the Company or the holder on the terms
provided in those shares.

(f)      The Directors can make calls upon members in respect of moneys unpaid
on their shares.

(g)      The Articles of Association prevent any person, save for certain
exceptions, from directly or indirectly owning or controlling shares giving that
person the right to cast 15% or more of the votes at a general meeting of the
Company. The holder of such shares shall not be entitled to attend or vote at
any general meeting of the Company or exercise any other right in relation to
the meeting until the holder complies with a notice under the Articles of
Association to dispose of a sufficient number of such shares in order to cease
to fall within this provision.

4)       Class Rights. Rights attached to a class of shares may be varied with
the consent, in writing, of not less than 75% of the issued shares of that class
or with the sanction of an extraordinary resolution passed at a separate general
meeting of the holders of that class of shares. The necessary quorum of the
meeting shall be two persons present in person holding at least one-third of the
nominal amount of issued shares of the class.

5)       Shareholder Meetings. Notice of a general meeting shall be given to all
members, each of the Directors and the auditors. At least twenty-one clear days'
notice in writing is to be given for an Annual General Meeting or an
Extraordinary General Meeting at which a special resolution is proposed, or a
resolution is proposed of which special notice has been given to the Company.
For any other Extraordinary General Meeting, at least fourteen clear days'
notice in writing must be given. A meeting shall be deemed to be duly called if
it is agreed by all members entitled to attend and vote, in the case of an
Annual General Meeting, and by a majority of members holding not less than 95%
of the nominal value of shares giving the right to vote in the case of an
Extraordinary General Meeting. A quorum of three persons entitled to vote on the
business to be transacted must be present at the time of the meeting and
throughout. As to admission, the Directors may make such arrangements as are
necessary for the security of the meeting. They are entitled to refuse entry to
any person not complying with such arrangements, requirements or restrictions.

6)       Limitations on Shareholdings. The Articles of Association place a limit
on the rights to own securities. No person, unless permitted under Article 51 of
the Articles of Association, may directly or indirectly own or control shares
giving the right to cast 15% or more of the votes at a General Meeting of the
Company. The holder of such shares shall not be entitled to attend or vote at
any

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General Meeting of the Company or exercise any other right in relation to the
meeting until the holder complies with a notice under Article 51 of the Articles
of Association to dispose of a sufficient number of such shares in order to
cease to fall within this provision. There are no limitations relating to
non-resident or foreign shareholders.

7)       Purchase of own shares. The Company is permitted to purchase its own
shares but only where this action has been sanctioned by an extraordinary
resolution.

                                       3Prepared by R.R. Donnelley Financial -- Scottish Power Annual Report 2001-02

  
 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 
 

 

 1 

  
 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 
 

 12 

 (“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 
 

 13 

 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 
 

 14 

 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. 
 

 15 

  
 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 
 

 16 

 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. 
 

 17 

 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. 
 

 18 

  
 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

 

 19 

 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 
 

 20 

 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 
 

 21 

 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 (“NOX”) 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 NOX control equipment on some 
 

 22 

 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. 
 

 23 

  
 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, NOX 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 NOX 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 NOX 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 
 

 25 

 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.

 

 26 

 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. 
 

 27 

  
 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
 
	  	  	 
	  	 
	  	 
	  	 
	  	 
	  	 
	  	 
	  	 
	  	 

 
 

 28 

  
 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
 
	  	  	 
	  	 
	  	 
	  	 
	  	 

 
 

 29 

  
 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. 
 

 

 31 

  
 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.

 

 37 

  
 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 
 

 38 

 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. 
 

 39 

  
 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. 
 

 40 

  
 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 
 

 41 

 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 
 

 42 

 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 
 

 43 

  
 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. 
 

 44 

  
 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. 
 

 45 

  
 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. 
 

 47 

  
 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. 

 48 

 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.

  
 

 53 

  
 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 
 

 115 

  
 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 
 

 116 

 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 
 

 117 

 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. 
 

 118 

 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. 
 

 119 

  
 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. 
 

 120 

  
 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 
 

 121 

  
 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
 	  	  	  	  	  	  	  	  

 
 

 122 

 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
 
	
	
	
	
	
	
	

 
  
 

 123

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