SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

____________
FORM 20-F

o	REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934 OR
x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended March 31, 2001
	OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ________ to ________ ______________ SCOTTISH POWER plc (Exact name of Registrant as specified in its charter)
	SCOTLAND (Jurisdiction of incorporation or organization)
	1 Atlantic Quay, Glasgow G2 8SP, Scotland (Address of principal executive offices)
	Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Ordinary shares of 50p each ("Ordinary Shares")	New York Stock Exchange*
American Depositary Shares ("ADSs") Each of which represents 4 Ordinary Shares	New York Stock Exchange
_____

^* Not for trading but only in connection with the registration of ADSs pursuant to the requirements of the Securities and Exchange Commission.

________________
Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

         Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report.

	Ordinary Shares of 50p each	1,849,025,792 shares (as of March 31, 2001)
	Special rights non-voting redeemable preference share of £1	1 share (as of March 31, 2001)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
	Yes x	No o
Indicate by check mark which financial statement item the registrant has elected to follow.
	Item 17 o	Item 18 x

PART I

Item 1.	Identity of Directors, Senior Management and Advisers
	Not applicable.
Item 2.	Offer Statistics and Expected Timetable
	Not applicable.
Item 3.	Key Information
	The information set forth under the headings " Exchange Rates " on page 70, " Five Year Summary " on page 116 and " Dividends " on pages 119-120 of the Company's 2000-01 Annual Report and Accounts contained in its Report on Form 6-K dated June 21, 2001 is incorporated herein by reference.
Item 4.	Information on the Company
	The information set forth under the headings " Business Review " on pages 4-40, " Notes to the Group Profit and Loss Account " on pages 74-77 and " Agent for US Federal Securities Laws " on page 125 of the Company's 2000-01 Annual Report and Accounts contained in its Report on Form 6-K dated June 21, 2001 is incorporated herein by reference.
Item 5.	Operating and Financial Review and Prospects
	The information set forth under the headings " Group Research and Development " on page 16 and " Financial Review " on pages 41-53 of the Company's 2000-01 Annual Report and Accounts contained in Exhibit 10.2 is incorporated herein by reference.
Item 6.	Directors, Senior Management and Employees
	The information set forth under the headings " Group Employees " on pages 13-14, " Board of Directors " on pages 54-55, " Corporate Governance " on pages 56-57, " Remuneration Report of the Directors " on pages 58-65 and " Employee Information " on pages 74-75 of the Company's 2000-01 Annual Report and Accounts contained in its Report on Form 6-K dated June 21, 2001 is incorporated herein by reference.
Item 7.	Major Shareholders and Related Party Transactions
	The information set forth under the headings " Remuneration Report of the Directors " on pages 62-65, " Related Party Transactions " on page 104, " Nature of Trading Market " on page 118, " Substantial Shareholdings " on page 119 and " Control of Company " on page 119 of the Company's 2000-01 Annual Report and Accounts contained in its Report on Form 6-K dated June 21, 2001 is incorporated herein by reference.
Item 8.	Financial Information
	The information set forth under the headings " Litigation " on page 34, " Accounting Developments " on page 52, " UK GAAP to US GAAP Reconciliation " on pages 52-53, " Accounts " on pages 66-115 and " Dividends " on pages 119-120 of the Company's 2000-01 Annual Report and Accounts contained in its Report on Form 6-K dated June 21, 2001 is incorporated herein by reference.
Item 9.	The Offer and Listing
	The information set forth under the heading " Nature of the Trading Market " on page 118 of the Company's 2000-01 Annual Report and Accounts contained in its Report on Form 6-K dated June 21, 2001 is incorporated herein by reference.
Item 10.	Additional Information
	The information contained in Exhibit 10.1 and the information set forth under the headings " Business Review " on pages 4-34, " Quantitative and Qualitative Disclosures About Market Risk " on pages 50-52, " Independent Auditors' Report " on page 115, " Dividends " on pages 119-120, " Exchange Controls and Other Limitations Affecting Security Holders " on page 120, " Taxation " on page 120 and " Financial Calendar " on page 124 of the Company's 2000-01 Annual Report and Accounts contained in its Report on Form 6-K dated June 21, 2001 is incorporated herein by reference.
Item 11.	Quantitative and Qualitative Disclosures About Market Risk
	The information set forth under the headings " Treasury " on pages 49-50 and " Quantitative and Qualitative Disclosures About Market Risk " on pages 50-52 of the Company's 2000-01 Annual Report and Accounts contained in its Report on Form 6-K dated June 21, 2001 is incorporated herein by reference.
Item 12.	Description of the Securities Other than Equity Securities
	Not applicable.

PART II

Item 13.	Defaults, Dividends Arrearages and Delinquencies
	Not applicable.
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds
	The information contained in Exhibit 10.1 and the information set forth under the heading " Investor Information " on pages 118-123 of the Company's 2000-01 Annual Report and Accounts contained in its Report on Form 6-K dated June 21, 2001 is incorporated herein by reference.
Item 15.	(Reserved)
	Not applicable.
Item 16.	(Reserved)
	Not applicable.

PART IV

Item 17.	Financial Statements
	The Company has responded to Item 18 in lieu of this Item.
Item 18.	Financial Statements
	The information set forth under the headings " Litigation " on page 34, " Accounting Developments " on page 52, " UK GAAP to US GAAP Reconciliation " on pages 52-55 and " Accounts " on pages 66-115 of the Company's 2000-01 Annual Report and Accounts contained in its Report on Form 6-K dated June 21, 2001 is incorporated herein by reference.
Item 19.	Exhibits
	The Company's responses to the requirements of Form 20-F have been incorporated by reference to the information referred to above that is in the Company's Report on Form 6-K that contains its 2000-01 Annual Report and Accounts which was filed on July 5, 2000. Pursuant to Rule 12b-23(a) of the Commission, attached hereto as an exhibit is the information incorporated into this Report by reference to such Form 6-K Report of the Company.

1.1.	Amended Memorandum of Association of Scottish Power plc. previously filed as an Exhibit to Scottish Power plc's Annual Report and Accounts on Form 20-F on September 28, 2000
1.2	Articles of Association of Scottish Power plc.
4.1	Contract of Employment between Scottish Power plc and Ian Russell
4.2	Contract of Employment between Scottish Power plc and Charles Berry
4.3	Contract of Employment between Scottish Power plc and David Nish
4.4	Contract of Employment between Scottish Power plc and Alan Richardson
4.5	Contract of Employment between Scottish Power plc and Ken Vowles
4.6	£1 billion multi-currency revolving credit facility dated June 5, 2001 arranged by The Bank of Tokyo-Mitsubishi, Ltd., Commerzbank Aktiengesellschaft, London Branch J.P. Morgan plc and The Royal Bank of Scotland plc
4.7	Revised Scottish Power UK plc - Generation, Transmission and Public Electricity Supply License document dated September 2000, as amended and modified
4.8	Amended and Restated Trust Deed dated December 1, 2000 related to the Scottish Power UK plc $4 billion debt issuance programme
4.9	Instrument of Appointment (Operating License) dated September 5, 2000 by the Secretary of State for the Environment of Southern Water Services Limited as a water and sewerage undertaker under the Water Act of 1989 including amendments previously filed as an Exhibit to Scottish Power plc's Annual Report and Accounts on Form 20-F on September 28, 2000
8.1	List of Subsidiaries
10.1	Summary of Memorandum and Articles of Association

        Pursuant to the requirements of Section 12 of the Securities Act of 1934, the registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Scottish Power plc, Registrant By:  /s/ David Nish                              Director
Dated September 28, 2001

EXHIBIT INDEX
Description
1.1	Amended Memorandum of Association of Scottish Power plc. previously filed as an Exhibit to Scottish Power plc's Annual Report and Accounts on Form 20-F on September 28, 2000
1.2	Articles of Association of Scottish Power plc.
4.1	Contract of Employment between Scottish Power plc and Ian Russell
4.2	Contract of Employment between Scottish Power plc and Charles Berry
4.3	Contract of Employment between Scottish Power plc and David Nish
4.4	Contract of Employment between Scottish Power plc and Alan Richardson
4.5	Contract of Employment between Scottish Power plc and Ken Vowles
4.6	£1 billion multi-currency revolving credit facility dated June 5, 2001 arranged by The Bank of Tokyo-Mitsubishi, Ltd., Commerzbank Aktiengesellschaft, London Branch J.P. Morgan plc and The Royal Bank of Scotland plc
4.7	Revised Scottish Power UK plc - Generation, Transmission and Public Electricity Supply License document dated September 2000, as amended and modified
4.8	Amended and Restated Trust Deed dated December 1, 2000 related to the Scottish Power UK plc $4 billion debt issuance programme
4.9	Instrument of Appointment (Operating License) dated September 5, 2000 by the Secretary of State for the Environment of Southern Water Services Limited as a water and sewerage undertaker under the Water Act of 1989 including amendments previously filed as an Exhibit to Scottish Power plc's Annual Report and Accounts on Form 20-F on September 28, 2000
8.1	List of Subsidiaries
10.1	Summary of Memorandum and Articles of Association

• UK Menu     • Cross Reference to Form 20-F (US)

Main Menu (UK)

Report of the Directors
Financial Highlights
Business Review
Summary of Key Operating Statistics
Financial Review
Board of Directors
Corporate Governance
Remuneration Report of the Directors

Annual Accounts
Accounting Policies and Definitions
Group Profit and Loss Account
Notes to the Group Profit and Loss Account
Group Cash Flow Statement
Notes to the Group Cash Flow Statement
Group Balance Sheet
Notes to the Group Balance Sheet
Company Balance Sheet
Notes to the Company Balance Sheet
Principal Subsidiary Undertakings and Other Investments
Independent Auditors Report
Five Year Summary
Glossary of Financial Terms and US Equivalents

Investor Information
Historical Share Prices
Exchange Rates
Dividends
Taxation of Dividends
Financial Calendar
Shareholder Services

• UK Menu     • Cross Reference to Form 20-F (US)

Cross Reference to Form 20-F (US)

Item 1
Identity of Directors, Senior Management and Advisers n/a Item 2
Offer Statistics and Expected Timetable n/a Item 3
Key Information Five Year Summary
Exchange Rates
Dividends Item 4
Information on the Company Business Review
Notes to the Group Profit and Loss Account
Agent for US Federal Securities Laws Item 5
Operating and Financial Review and Prospects Group Research and Development
Financial Review Item 6
Directors, Senior Management and Employees Group Employees
Board of Directors
Corporate Governance
Remuneration Report of the Directors
Employee Information Item 7
Major Shareholders and Related Party Transactions Remuneration Report of the Directors
Related Party Transactions
Nature of Trading Market
Substantial Shareholdings
Control of Company Item 8
Financial Information Litigation
Accounting Developments
UK GAAP to US GAAP Reconciliation
Accounts
Dividends Item 9
The Offer and Listing Nature of Trading Market Item 10
Additional Information Business Review – Description of Business – Wholesale Sales and Purchased Power
Business Review – Description of Legislative and Regulatory Background – Regional Transmission Organisation ("RTO")
Independent Auditors' Report
Dividends
Memorandum and Articles of Association
Exchange Controls and Other Limitations Affecting Security Holders
Taxation of Dividends
Financial Calendar Item 11
Quantitative and Qualitative Disclosures about Market Risk Treasury
Quantitative and Qualitative Disclosures about Market Risk Item 12
Description of Securities Other than Equity Securities n/a Item 13
Defaults, Dividend Arrearages and Delinquencies n/a Item 14
Material Modifications to the Rights of Security Holders and Use of Proceeds Investor Information Item 15 (Reserved) n/a Item 16 (Reserved) n/a Item 17
Financial Statements n/a Item 18
Financial Statements Litigation
Accounting Developments
UK GAAP to US GAAP Reconciliation
Accounts Item 19
Exhibits n/a

• UK Menu     • Cross Reference to Form 20-F (US)

Financial Highlights

Turnover £m	Operating Profit* £m
Earnings per share* pence	Total shareholder returnpence Capital appreciation plus dividend reinvestment for £1 invested on 1 April 1996 Source: Datastream

	2001		2000
Turnover	£6,349	m	£4,115	m
Operating profit *	£970	m	£961	m
Profit before tax *	£628	m	£736	m
Earnings per share *	27.9	p	38.0	p
Dividends per share	26.0	p	24.8	p
* before exceptional items and goodwill amortisation

• UK Menu     • Cross Reference to Form 20-F (US)

Business Review

Description of Business

Scottish Power plc ("ScottishPower") is a major, international energy group listed on both the New York and London Stock Exchanges. It had a turnover of £6.3 ($9.0) billion in 2000–01 and, during the year, market capitalisation reached a high of £10.6 ($15.1) billion. ScottishPower and its subsidiaries serve approaching seven million homes and businesses in the northwest US and across the UK providing electricity generation, transmission, distribution and supply services in both countries. The company's US activities extend to coal mining. In Great Britain, ScottishPower also supplies gas, provides water and wastewater, telephony and Internet services and retails electrical, gas and home entertainment appliances.

Since its creation upon privatisation in 1991, ScottishPower has grown rapidly both by organic growth in the (now fully competitive) British electricity, gas and telephony markets and through strategic acquisitions in the UK and the merger with PacifiCorp in the US. ScottishPower now holds substantial positions in both the US and UK energy markets having, during 2000-01, successfully disposed of non-strategic holdings in Australia and the UK.

Strategic Context
ScottishPower is committed to delivering value for shareholders through reshaping and improving the performance of its existing businesses: cutting out duplication and withdrawing from marginal activities, such as the sale of financial services and telecoms to UK households, in order to recycle capital and management effort into profitable, growing businesses. In both the US and the UK, the group intends to expand its integrated, international energy business by focusing on the value chain connecting fuel, generation, commercial and trading, and energy supply. The aim is to capture opportunities for earnings growth by looking right along the whole of the energy value chain. In addition, the group has proven expertise in acquiring, transforming and operating large energy businesses and intends to evaluate selective acquisitions that build upon the integrated energy value chain and enable the group to deploy its skills in transforming wires businesses.

To provide a sharper focus on further developing the business, the group has been restructured into three divisions. The US Division includes PacifiCorp's regulated and unregulated energy businesses and will concentrate on the growth in US energy needs and the opportunities in the western US power markets. The UK Division consists of the UK generation assets, the commercial and trading activities and the energy supply business, all of which have been integrated to capture opportunities for growth throughout the energy value chain. The Infrastructure Division, which includes Power Systems and Southern Water in the UK, will focus on improving business performance, transforming new businesses and will also seek benefits between the US and UK infrastructure businesses. All three divisions have a clear focus on value creation and earnings growth.

US Division
On 29 November 1999, PacifiCorp and ScottishPower completed a merger under which PacifiCorp became an indirect subsidiary of ScottishPower. PacifiCorp continues to operate under its established name, and its headquarters remain in Portland, Oregon, but as a result of the merger, its operations are now subject to the requirements and restrictions of the Public Utility Holding Company Act of 1935.

Also 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. PacifiCorp has terminated all business development activities outside the US and completed the sale of its indirect ownership of Powercor and its indirect interest in Hazelwood, both in Australia. PacifiCorp's wholly owned subsidiary, PacifiCorp Group Holdings Company, owns the stock of subsidiaries conducting businesses not regulated as domestic electricity providers and continues to liquidate portions of the loan and leasing portfolio of PacifiCorp Financial Services, Inc. ("PFS"). PFS presently expects to retain only its tax-advantaged investments in leveraged lease assets and to limit its pursuit of new tax-advantaged investment opportunities.

Principal Business Activities
PacifiCorp conducts its retail electricity supply operations as Pacific Power and Utah Power and engages in power production and sales on a wholesale basis under the name PacifiCorp.

Power Production and Fuel Supply
PacifiCorp's generating facilities are interconnected through its own transmission lines or by contract through the lines of others. Substantially all generating facilities and reservoirs located within the western states are managed on a co-ordinated basis to obtain maximum load carrying capability and efficiency.

During the third quarter of 2000-01 and continuing into the fourth quarter of 2000-01, the demand for electricity in the western US exceeded the available generation resources. As a result, supply shortages occurred, particularly affecting electricity availability in California. None of PacifiCorp's service territory has experienced such severe supply shortages, however, resources and demand in the region are in a tightly balanced condition. A substantial portion of the power provided to the Californian market from the Pacific Northwest has come from hydro-electricity generation facilities. Those resources are now reduced due to the low snow pack and precipitation, resulting in low stream flow being experienced over the past six months. The outlook for improvement in the availability of electricity supply for the next year is poor. In part, this is due to the continuation of high demand, low hydro resource availability in the water year ending September 2001, demands on hydro resources for irrigation and migrating fish protection and lead time needed to place new generation facilities into production. PacifiCorp is accelerating its efforts to bring new generation on-line.

PacifiCorp owns or has interests in generating plants with an aggregate nameplate rating of 8,280 megawatts ("MW") and plant net capability of 7,832 MW (see Table 1 ). With its present generating facilities, under average water conditions, PacifiCorp would expect that approximately 5% of its energy requirements for 2001-02 would be supplied by its hydro-electricity plants and 67% by its thermal plants. The balance of 28% would be obtained under long-term purchase contracts, interchange and other purchase arrangements. The period of decreased rainfall in the Pacific Northwest may cause the hydro-electricity expectations not to be met, as the needs of fish migration and irrigation could use water that otherwise would be used to produce electricity. During 2000-01, approximately 4% and 60% of PacifiCorp's energy requirements were supplied by its hydro-electricity and thermal generation plants, respectively, and the remaining 36% by purchased power. The thermal generation percentage contribution was reduced by the sale of the Centralia plant in May 2000 and the Hunter unit outage. This outage occurred on 24 November 2000 and continued until the generation unit began re-commissioning on 30 April 2001 in line with the estimated restoration timetable of four to six months.

As at 31 March 2001, PacifiCorp had 229 million tons of recoverable coal reserves that are mined by PacifiCorp or its affiliates and are dedicated to nearby PacifiCorp operated generating plants (see Table 2 ). During 2000-01, these mines supplied approximately half of PacifiCorp's total coal requirements. Coal is also acquired through long-term and short-term contracts. PacifiCorp has also entered into long-term and short-term natural gas contracts to supply its generating plants that use natural gas with the fuel needed for operations.

Wholesale Sales and Purchased Power
Wholesale sales of power contribute significantly to total revenues, even though PacifiCorp has scaled back wholesale sales from 1998 levels. PacifiCorp's wholesale sales complement its retail business and enhance the efficient use of its generating capacity over the long-term. PacifiCorp's transmission system connects with power providers in the Pacific Northwest having low-cost hydro-electric generation and with others in California and the southwestern US having higher-cost, fossil-fuel generation. Historically, during the winter, PacifiCorp was able to purchase power from plants in the southwestern US, either for its own peak requirements or for resale to other regional energy retailers. During the summer, PacifiCorp was historically able to sell excess power to the southwestern US, to assist in meeting the region's peak requirements. If PacifiCorp is in a surplus power position, it is able to sell excess generation into the wholesale market.

The supply of power has not kept pace with the growing demand in the western US, and PacifiCorp is experiencing the effect of high market prices associated with this shortage. Prices paid by PacifiCorp to provide certain load balancing resources may continue to exceed the amounts it receives through retail rates and wholesale prices, although many of PacifiCorp's purchased power contracts have fixed price components, which provide some protection against the current price volatility. In addition to its base of thermal and hydro-electricity generation assets, PacifiCorp uses a mix of long-term and short-term firm power purchases and non-firm purchases to meet its load obligations and to make sales to other energy providers. Long-term firm power purchases supplied 13% of PacifiCorp's total energy requirements in 2000-01. Short-term firm and non-firm power purchases supplied 23% of PacifiCorp's total energy requirements in 2000-01.

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 2001 was $65 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. The next scheduled price change will be on 1 October 2001, when a slight decline in price is expected. 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 2000-01, PacifiCorp purchased an average of 109 MW from qualifying facilities, compared to an average of 112 MW in 1999-00.

The Energy Policy Act, passed in 1992, opened wholesale competition to energy brokers, independent power producers and power marketers. In 1996, the Federal Energy Regulatory Commission ("FERC") ordered all investor-owned power companies to allow other power wholesalers access to their transmission systems at the same price and terms the companies would apply to their own wholesale customers. Competition is also influenced by availability and price of alternate energy sources and the general demand for electrical power. PacifiCorp has formulated strategies to meet these challenges and is marketing power supply services to other power providers in the western US, including dispatch assistance, daily system load monitoring, backup power, power storage and power marketing.

Retail Electricity Sales
PacifiCorp serves approximately 1.5 million retail customers in service territories aggregating about 135,800 square miles in portions of six western states: Utah, Oregon, Wyoming, Washington, Idaho and California. On 1 December 2000, PacifiCorp filed requests with the utility commissions in Utah, Oregon, Wyoming, Washington and Idaho to change the way PacifiCorp is regulated. A similar filing is planned for California. The proposed plan would change PacifiCorp's legal and regulatory structure and result in the creation of six state electricity distribution companies, a generation company and a service company, all subsidiaries of a new holding company. The proposal is designed to allow each state to pursue the regulatory policies it deems appropriate, without affecting customers in other states or treating shareholders unfairly. Approval for these proposals must be obtained from the utility commissions in Utah, Oregon, Wyoming, Washington, Idaho and California, as well as from FERC and the Securities and Exchange Commission ("SEC"). This process is expected to take more than a year.

The PacifiCorp service area's diverse regional economies range from rural, agricultural and mining areas to urban manufacturing and government service centres. No one segment of the economy dominates, which mitigates exposure to economic swings. In the eastern portion of the service area, 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, 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. The geographical distribution of PacifiCorp's retail electricity operating revenues for the year ended 31 March 2001 was Utah, 38%; Oregon, 33%; Wyoming, 13%; Washington, 8%; Idaho, 6%; and California, 2%. (PacifiCorp is currently seeking to exit operations in California. See " Proposed Asset Additions and Dispositions ").

As a result of the geographically diversified area of operations, PacifiCorp's service territory has historically had complementary seasonal load patterns. In the western sector, customer demand peaks in the winter months due to space heating requirements. In the eastern sector, customer demand peaks in the summer when irrigation and cooling systems are heavily used. Many factors affect per customer consumption of electricity. For residential customers, within a given year, weather conditions are the dominant cause of usage variations from normal seasonal patterns. However, the price of electricity is also considered a significant factor. In response to recent region-wide electricity supply shortages, PacifiCorp is actively promoting electricity conservation programmes, which may cause usage variations. During 2000-01, no single retail customer accounted for more than 2% of PacifiCorp's retail electricity revenues and the 20 largest retail customers accounted for 15% of total retail electricity revenues. Trends in energy sales by class of customer are set out in Table 3 , Table 4 and Table 5 .

PacifiCorp continues to experience economic growth in several portions of its service territory, and retail energy sales for PacifiCorp have grown at a compound annual rate of 2.1% since 1995. This increase in demand is happening throughout the Western System Coordinating Council ("WSCC") area, due in large part to economic growth. This increase in demand may not continue depending upon several factors, including the impact of demand side management programmes and higher prices. 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 power costs. PacifiCorp is pursuing price increases in jurisdictions where it does not earn an appropriate rate of return and will seek operating efficiencies as outlined in the Transition Plan.

For the periods 2002 to 2005, the average annual growth in retail megawatt hour ("MWh") sales in PacifiCorp's franchise service territories is estimated to be about 1.7%, excluding the potential effects of decreased demand resulting from conservation efforts and higher prices. Because of price increases throughout the region, PacifiCorp anticipates that demand growth will slow or may even reverse. During this period, PacifiCorp may lose retail energy sales to other suppliers in connection with deregulation of the electricity industry. As the electricity industry evolves towards deregulation, PacifiCorp 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.

In many cases, customers have the option to switch energy sources for heating and air conditioning. In addition, some of PacifiCorp's industrial customers are seeking choice of suppliers, options to build their own generation or co-generation, or the use of alternative energy sources such as natural gas. During 2000-01, PacifiCorp continued to operate its electricity distribution and retail sales business as a regulated monopoly throughout most of its franchise service territories. However, PacifiCorp anticipates increasing competition, principally as a result of industry restructuring, deregulation and increased marketing by alternative energy suppliers. When a competitive marketplace exists, customers will make their energy purchasing decision based upon many factors, including price, service and system reliability. PacifiCorp supports increased customer choice under terms and conditions that are equitable to all stakeholders.

With effect from 1 January 1998, the California Public Utilities Commission ("CPUC") adopted rules regulating the non-tariffed sale of energy and energy products and services by power companies and their affiliates. The rules also mandated a 10% rate reduction in tariffed electricity prices in California, which resulted in a $3.5 million annual reduction in PacifiCorp's revenues. PacifiCorp has decided to refrain from marketing non-tariffed energy products and services to retail customers in California but intends to continue limited purchases and sales in the wholesale business, selling to utilities in California and marketers elsewhere in the western US.

Deregulation in Oregon has been moving forward, but caution is being taken to avoid the problems that have been encountered in California. It is expected that regulators will act prudently to protect the state's energy supplies from the potential hazards of deregulation. Four other states, Utah, Wyoming, Washington and Idaho, have been slow in deregulating their electricity markets. See " US Business Regulation ".

Proposed Asset Additions and Dispositions
In July 1998, PacifiCorp announced its intention to sell its California electricity distribution assets. This action was in response to the continued decline in earnings on the assets and the changes in the legislative and regulatory environments in California. PacifiCorp had an agreement with Nor-Cal Electric Authority ("Nor-Cal") for the sale of its California electricity assets for $178 million. On 21 December 2000, the CPUC approved an Administrative Law Judge's decision to dismiss the application for approval of the sale. PacifiCorp is currently in discussion with Nor-Cal to evaluate its options with respect to this sale.

On 12 April 2000, PacifiCorp announced the closure of the Trail Mountain Mine in the autumn of 2001 after the lease is mined out. The mine is located in Central Utah and supplied fuel to the Hunter Plant. The fuel for the Hunter Plant will be provided by PacifiCorp's Deer Creek Mine and other Utah mines. PacifiCorp filed applications with the Utah, Oregon, Wyoming and Idaho utility commissions to defer $27 million in unrecovered costs associated with the mine and, in April 2001, the Wyoming and Idaho commissions approved deferred accounting treatment.

PFS has four plants in the Birmingham, Alabama area that produce a synthetic coal fuel using technology licensed from Covol Technologies, Inc., which is designed to qualify for tax credits under Section 29 of the Internal Revenue Code. PacifiCorp does not currently have sufficient income tax liability to make use of all of these tax credits and is actively seeking a buyer for its synthetic coal producing plants.

• UK Menu     • Cross Reference to Form 20-F (US)

Business Review

UK Division

Principal Business Activities
The group's UK Division operates ScottishPower's generating stations, deals in the wholesale trading of electricity and gas and is responsible for the sales and marketing of electricity, gas and related services to customers throughout Great Britain and for billing, receipting and handling enquiries in respect of these services. The business objective is to create competitive advantage for ScottishPower by optimising the energy value chain.

Generation Portfolio

ScottishPower's owned generation capacity comprises coal, gas, hydro and wind power and has available 4,500 MW, see Table 7 , after taking into account the impact of contractual obligations to supply Scottish & Southern with a proportion of its coal-fired capacity. Generation capacity in England & Wales is now approximately 1,000 MW following the purchase of the Rye House combined-cycle gas turbine ("CCGT") station from Powergen and the start of commercial operation of the newly constructed 400 MW CCGT station near Brighton in which ScottishPower has a 50% economic and voting interest (with the balance being held by American Electric Power, the US parent company of SEEBOARD). Acquisition of additional thermal generation capacity is kept under continuing review, the Rye House purchase being an example of the pursuit of viable commercial opportunities.

ScottishPower's windfarm business continues to expand with two new windfarms being commissioned during 2000-01: Dun Law (17 MW) in the Scottish Borders and Hare Hill (13 MW) in East Ayrshire. Hare Hill operates without a Scottish Renewables Obligation contract and, as such, is the first fully commercial windfarm in the UK. The group now has interests in ten windfarms in the UK and Ireland with a total owned capacity of 98 MW, producing sufficient power for some 100,000 typical homes. Infrastructure works are largely completed and turbine erection is due to commence in August 2001 at Beinn an Tuirc windfarm in Kintyre, a high wind speed site with 30 MW peak output, which will be the most productive windfarm in the UK when it becomes fully operational, planned for December 2001. A number of other windfarms are under development to ensure that the company target of 10% generation from renewables by 2010 is met. Dialogue with key stakeholders including local authorities, Scottish Natural Heritage, The Royal Society for the Protection of Birds and local communities is well advanced.

In addition to its own capacity, ScottishPower has access to nuclear energy, from British Energy, and gas-fired, oil-fired and hydro-electricity from Scottish & Southern under contracts established in connection with the restructuring of the UK electricity industry in 1990 and 1991. Additional information concerning the group's generating capacity available under contract is shown in Table 8 . These resources combine to give ScottishPower a flexible fuel portfolio and result in total available capacity of some 7,300 MW.

Station Performance
The Generation business aims to achieve best practice in terms of generation performance and costs, while at the same time maintaining the flexibility to optimise energy trading, and has undertaken extensive benchmarking of all its activities against an international peer group. Investment programmes to implement the findings continue in Longannet and Cockenzie power stations, consolidating business efficiency improvements through the use of key performance indicators and further benchmarking. However, it is the intention of the business to drive costs down further through continued reductions in fixed costs, plus improved engineering and operational efficiencies and enhanced environmental performance. The group has a detailed engineering strategy to upgrade its existing coal stations. Management believes that, as a result of its ongoing maintenance programme, ScottishPower's portfolio of UK power stations is in a condition to support current and expected generation output.

Fuel Strategy and Sourcing
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, gas and oil.

Coal – ScottishPower currently purchases the majority of its coal from Scottish suppliers under two long-term contracts (with remaining terms of two and three years), with the principal supplier being The Scottish Coal (Deep Mine) Company Limited. These purchase commitments secure the major part of ScottishPower's coal requirements from local sources. In 2000-01, ScottishPower coal consumption was some 36% up on the previous year. This equated to an increase of some 1.62 million tonnes in marginal coal requirements which was purchased from a mixture of indigenous and imported coal suppliers.

Gas – ScottishPower purchases gas to meet the needs of the group's generation and supply businesses using a combination of long, medium and short-term contracts with gas producers for the supply of gas on a non-interruptible basis. The group has three long-term contracts (with remaining terms of 7, 13 and 16 years) for supply from major gas fields. For the latter two, these contracts can terminate earlier if the reserves of the fields have been fully depleted. In addition, ScottishPower is party to agreements which require Scottish & Southern to purchase and accept delivery of gas at Peterhead power station from the Miller gas field. This agreement also continues in force until the reserves of the field have been fully depleted.

The development of Hatfield Moors as a gas storage site was completed during the winter of 1999-00 with use of it from the latter part of that winter. During the 2000-01 winter, the storage facility was extensively used to meet the peak demands of some 450,000 customers, as well as fully exploiting the sales opportunities both when market prices rose to the highest sustained levels experienced since the market opened to competition in 1996 and arising from the volatility of gas prices between mid-week and weekends. In light of the experience gained, a feasibility study is underway aimed at substantially upgrading the daily delivery rates and incorporating an additional reservoir to increase capacity. In addition, ScottishPower has entered into a development agreement with Ineos Chlor which, subject to receipt of Planning Approval, will result in the development of a salt cavern gas storage facility at Byley in Cheshire. Planning approval is anticipated during the second half of this year which would permit partial operation for the 2004-05 winter.

Oil – From time-to-time, ScottishPower purchases heavy fuel oil on the international spot market when favourable prices are available. Heavy fuel oil is therefore an opportunity purchase rather than a firm fuel source.

Sewage Sludge – Operating under the Private Finance Initiative, but managed through the Generation Business, ScottishPower subsidiary SMW Limited is building a facility at Daldowie sewage treatment plant which will produce pelletised sludge for use, under a back-to-back contract with ScottishPower, at Longannet. Reception, storage and co-burning facilities are under construction at Longannet which will allow the pellets to be blended with the coal used at the station in either of two modified boilers. The facilities could handle up to 100,000 tonnes of pellets per year and are expected to commission in late 2001.

Generation Sales
Generation sales totalled 28,959 gigawatt hours ("GWh") in 2000-01, comfortably the highest ever generation flow in total from ScottishPower owned plant, as the group's low-cost coal-fired capacity substituted for nuclear plant shortfall. Approximately 18,830 GWh were attributable to ScottishPower's energy business, with the remaining 10,129 GWh either being sold to other suppliers or exported via the interconnector to England & Wales.

The average utilisation of ScottishPower's two largest coal-fired stations, Longannet and Cockenzie, in 2000-01 was approximately 62% and 43%, respectively, boosted by the stations' ability to take advantage of market conditions. Strong representations are being made to the Office of Gas and Electricity Markets ("Ofgem") to protect ScottishPower's access to the growing interconnector capacity both in the interim arrangements for interconnector access and in the formal outcome of the current review of British Electricity Trading and Transmission Arrangements ("BETTA") which is expected to become effective during 2002-03.

Electricity Trading
Electricity trading, within the Energy Trading Centre, secures competitive advantage for the group through trading and optimising its position across the electricity value chain, continuously evaluating and managing risk exposure. Since privatisation in 1990, the major electricity trading risk was price volatility arising in the wholesale Pool market in England & Wales through the group's exposure as a generator (seller) and as a supplier (purchaser) of electricity, for which prices vary over time. Such exposure was managed through trading in contracts for differences with willing parties such as other generators, suppliers or intermediaries. From 27 March 2001, New Electricity Trading Arrangements ("NETA") were introduced in England & Wales moving from the compulsory Pool trading system to a bilateral market in which a more proactive approach to trading is now developing. New transitional trading arrangements are also in place to enable generators and suppliers operating in Scotland to trade with their counterparts in England & Wales and increase competition on a cross-border basis. This materially reduces the differences between the two markets, leading to a more liquid market throughout Great Britain.

As with the introduction of competition to the domestic electricity market in 1998, ScottishPower was at the forefront of system developments for NETA, being one of the first NETA participants to complete successful qualification testing in January 2001 and participating fully in the new market from its go-live date of 27 March 2001. Implementation of a number of systems took place in advance of the NETA go-live date, for example, the short- term demand forecasting system was deployed operationally well in advance of NETA. The electricity trading platform delivered is sufficiently flexible to allow for full integration of the gas and electricity trading systems, should this be required in the future.

NETA represents a radical change to the way in which electricity is traded and introduces penal imbalance charges, designed to promote highly efficient forecasting, trading and risk management on the part of all participants.

The Interconnector in England & Wales
ScottishPower has the ability to sell, or purchase, electricity in England & Wales via the interconnector which is shared by Scottish & Southern and British Nuclear Fuels Limited ("BNFL") under formal agreement. The current maximum capacity of the interconnector is 1,950 MW with an average capability in 2000-01 of 1,367 MW. An agreement has been made with the National Grid Company and Scottish & Southern to upgrade the maximum capacity of the interconnector to 2,200 MW. Planning approval has been granted by HM Government and completion of work on the upgrade of the Scotland-England transmission link to 2,200 MW is currently scheduled for Autumn 2002. ScottishPower's generation business will provide 75% of the capital cost of the upgrade and Scottish & Southern the other 25%. Pursuant to an agreement with Scottish & Southern, ScottishPower has the contractual right to 54% of the pre-upgrade capacity and up to 75% of the additional upgrade capacity of the interconnector.

ScottishPower's Licence only entitles it to reserve capacity to itself with the consent of Ofgem and obliges it to offer to enter into an agreement with any third party applicant for use of the interconnector. Following a determination and proposed determination by the Director General of Electricity Supply ("DGES") in December 1998 and April 2000 respectively, ScottishPower has made 196 MW from its share of the interconnector capacity available to BNFL, for the period from 1 January 1999 to 31 March 2002 and has made a robust response to an Ofgem proposal not to approve a reservation of any additional interconnector capacity for ScottishPower's own generation business. However, Ofgem is reviewing the arrangements for access to the interconnector as part of BETTA, the wider review of the transmission and wholesale trading arrangements in Britain as a whole, which will also ensure compliance and consistency with the EU Directive on electricity market liberalisation. ScottishPower broadly supports such reform, so long as it forms part of a package which addresses all aspects of the present Scottish wholesale market, and the company is actively engaged in the review.

Trading with Northern Ireland Electricity
ScottishPower has entered into an agreement with Northern Ireland Electricity ("NIE"), a subsidiary of Viridian Group plc, for the construction of a Scotland-Northern Ireland interconnector with a transfer capability of 250 MW; and an agreement for the supply by ScottishPower of around 1,095 GWh of electricity per year over a period of 70 months from the date of commissioning. These agreements amend and restate agreements originally entered into in 1994. Once completed, the Northern Ireland and marine sections of the Scotland-Northern Ireland interconnector will be owned by NIE, and the section from the Scottish converter station will be owned by ScottishPower. NIE will provide the full capital cost of this interconnector. It is anticipated that the Scotland-Northern Ireland interconnector will commence commercial operation in winter 2001-02.

Energy Supply
Since September 1998, when competition was extended to residential electricity customers, the strategic focus of the ScottishPower energy supply business has been defence of its existing markets, particularly 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 (formerly franchise area) residential customers remains at 75%. Significant progress has been made in establishing the systems, organisation and skills to achieve the necessary scale and margin performance in energy supply through incremental sales, strategic marketing alliances, such as those with J Sainsbury and Union Energy, and by bulk purchases where shareholder value is present, for example, in the acquisition of some 70,000 customers of the Gas Supply Company. Customer Sales & Services ("CS&S") remains strongly committed to developing the energy customer business with a focus on profitability, scale and customer service quality.

At 31 March 2001, ScottishPower held 3.5 million energy accounts, 800,000 being supplied with gas of which some 560,000 customers are supplied with both gas and electricity. CS&S is investing to provide ScottishPower with a strong platform from which to capitalise on a larger customer base. The priorities are accelerating the reduction of servicing costs to benchmark levels and enabling automated referral of customers to sales and retention channels suited to an increasingly competitive market.

Many British businesses are exploring the potential of multi-product bundles but, although CS&S has established that it has the skills to evaluate, develop and launch such offers, the group does not believe that shareholder value can be built on a sufficient scale to justify competing in the present stages of development of this broader market for home services. Both the Internet-based joint venture with The Royal Bank of Scotland and a trial offering of residential telephony have been discontinued by mutual agreement with the business partners involved.

Since the launch of the ScottishPower on-line energy enquiry site, CS&S has steadily developed its e-business capability, retaining a strictly practical focus on gas and electricity sales. The e-business capability is growing significantly as a channel to market and, in mid-2001, the site will be upgraded to allow customers to manage their own accounts on-line if they wish. Customers will then be able to 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.

Customer Service
The business' customer service Guaranteed Standards were maintained in the year ended 31 March 2001 at the high level set in the previous year, with over 99.99% of all electricity services provided currently matching or exceeding regulatory standards. Complaints regarding traditional home area electricity service in 2000-01 remained at the very low level of 955, representing only 4.1 complaints per 10,000 customers. Even in the more vigorously competitive gas and out of area electricity markets, with their unfamiliar new processes, complaint levels in the year to 31 March 2001 fell by 29% compared with the previous 12 months, contributing materially to an overall reduction in regulatory complaints of 19%.

Metering and Data Management
Accurate and timely customer registration, metering and settlement are crucial to delivering high-quality customer service and, recognising the importance of the extension of competition to metering, the ScottishPower Metering operation was established as a standalone business on 1 April 2000. Meter reading and operation is characterised by a large regional field force, working from home, which carries out over 12 million customer visits a year and fulfils most of ScottishPower's data management activities, from meter installation to data collection for gas, electricity and water customers.

In the competitive energy market, meter reading and operation form parts of an integrated data management process also covering customer registration, billing record set-up and agent registration. From 15 November 2000, ScottishPower has operated end-to-end process management for the provision and control of registration and billing data, in order to maximise efficiencies through streamlining the operation of these processes. The significant improvements in data quality are already leading to real improvements in customer service and operational cost savings are positioning the newly integrated data management business to retain market share, whilst exploiting opportunities to grow its data management activities across the UK.

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Business Review

Infrastructure Division

Principal Business Activities – Power Systems
ScottishPower owns and manages a substantial electricity network, comprising both the distribution system to customers in its two authorised areas and, in Scotland, its high voltage transmission system (132 kV and above). The latter includes all the assets of the England-Scotland interconnector which are in its Scottish authorised area. The main functions of the Power Systems business are to develop and maintain efficient, co-ordinated and economical networks, to facilitate competition in generation and supply and to adhere to approved standards of safety and reliability.

Within Power Systems, the focus continues to be on reducing costs and improving service. Its principal business activities involve the provision of new connections, construction and refurbishment of the system, maintenance and fault repair, setting tariffs and collecting revenues for the use of its authorised networks. Power Systems continues to focus strongly on the efficient delivery of electricity to customers in its service areas via its overhead and underground network. Investment in the business has included significant upgrade and refurbishment of the transmission and distribution systems. Power Systems has a distribution/transmission network which extends to 115,103 km, with 65,230 km of underground cables and some 49,873 km of overhead lines. Table 9 shows key information with respect to the group's UK transmission and distribution services in 2000-01.

Electricity Distribution
ScottishPower and Manweb each hold a Public Electricity Distributor ("PED") licence, allowing each company to undertake electricity distribution activities within its authorised area. The income derived from the distribution business is dependent on changes in the demand for electricity by customers in the home area. Demand for electricity is affected by such factors as growth and movements in 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. Table 10 and Table 11 set out the changes in GWh by customer type within the broadly stable levels of electricity distributed over ScottishPower and Manweb's distribution systems during the five most recent financial years.

The group is committed to providing its customers with an electricity supply which is safe and reliable. Both ScottishPower and Manweb operate networks to provide supplies within the guidelines for reliable electricity supplies set forth in the European Standard EN50160 entitled "Voltage Characteristics of Electricity Supplied by Public Distribution Systems". On 1 April 2000 the first phase of the new Asset Manager/Service Provider model organisation came into effect. Designed to focus on the key business processes, separating strategy and policy from their delivery, the new model enhances the focus of the business. The "Asset Manager" takes responsibility for extracting maximum value from the regulatory contract, whilst commercial pressures ensure that the "Service Providers" deliver the required service at market rates.

RuralCare
The focus of this two-year project has been to protect strategic overhead powerlines from the risk of falling trees.

Over 4,000 km, 8% of the total overhead network, has been cleared entailing the removal of approximately 300,000 trees, of which 85% were commercial softwoods. To compensate for the loss of trees, landowners were offered the replanting of two trees for every tree removed. In addition, the £1million RuralCare Grant Scheme was launched in October 2000 to encourage and support the creation of new native woodlands and the enhanced management of existing native and other woods for maximum public benefit. During blizzard weather conditions as experienced during the major storm on 26 February 2001, it is not unusual to lose power to thousands of customers due to fallen trees. The absence of tree-fall incidents in this emergency demonstrates that the RuralCare Project prevented a considerable number of customer interruptions and reduced the time to restore power supplies on this occasion alone.

Planning for Emergencies
Heavy snowfalls driven by a northerly wind struck the south of Scotland on the evening of 26 February 2001. This led to heavy ice accretion on the overhead line conductors which, in combination with the strong winds, caused conductors and poles (and in a few cases steel lattice towers) to fail. The transmission system experienced around 140 automatic re-close operations due to transient faults and five damage incidents. Across the distribution system some 1,100 faults were experienced of which almost 450 were major incidents. These failures were most pronounced in the Borders area where, at certain locations, groups of up to 30 poles on the same circuit required replacement. Emergency plans and procedures worked well and ensured a structured response to the emergency. Over 1,300 repair and generator installation staff from ScottishPower, other PEDs and contractors were mobilised following the declaration of the emergency. At the peak, on 27 February 2001, over 102,000 customers were without supply. The call handling systems and associated telecommunication equipment operated effectively for the duration of the storm.

Competition in Connections
Ofgem has released its proposals for increasing the competitive provision of connections to distribution networks, mainly through compliance measures designed to ensure that PEDs treat their own New Connections businesses in the same way that they would an external connections contractor. The ScottishPower New Connections business has been set up in anticipation of this regulatory development to ensure that it is in the best position to take advantage of the opportunities presented. Streamlined New Connections processes have been implemented covering design, estimation, payment, work scheduling and the issuing of confirmation letters – and significantly reducing the process time for design and estimation for multiple service projects.

Principal Business Activities – Southern Water
The region in which Southern Water operates occupies an area of approximately 10,450 km² in the counties of Kent, East and West Sussex, Hampshire and the Isle of Wight, and small parts of Wiltshire, Berkshire and Surrey. The region's coastline stretches 1,250 km from Swanscombe on the Thames Estuary to just beyond the Solent at Barton on Sea, including the Isle of Wight. The region has an estimated population of approximately 4.4 million. The portion of the region to which Southern Water supplies water covers a total area of some 4,450 km² , contains approximately 1 million premises and has a resident population of some 2.2 million. Local water companies supply the rest of the region's water requirements. Southern Water provides wastewater services to virtually all of the region, collecting wastewater from almost 1.8 million premises. In addition to the residential population, the businesses in Southern Water's region discharge industrial effluent having the equivalent strength of an additional population of about 465,000. Table 12 sets out key information with respect to Southern Water's activities in 2000-01.

Water Supply Business
Southern Water supplies, on average, 585 million litres of water per day, which is distributed through 13,302 km of water main. Southern Water's 104 water treatment works treat water from 132 water sources in the region with 70% of water supplied coming from underground sources. Water is pumped through the water mains by 541 pumping stations. Southern Water is also responsible for the operation and maintenance of four impounding reservoirs which have a total storage capacity of 42,390 million litres. The volume of water put into supply exhibits a pronounced seasonal variation between summer and winter. Typically, the peak seven-day demand in the summer is up to 40% higher than the annual average, and stems from increased residential usage and the influx of tourists to resort towns along the south coast and on the Isle of Wight.

The bulk of Southern Water's underground sources are located in chalk, with a small number of abstractions being made from sandstone aquifers. The water is of high quality and receives various forms of treatment appropriate to each source. These provide reductions in the level of pesticides, iron and manganese; the reduction of plumbosolvency; and in all cases protection against bacteria and other micro-organisms throughout the distribution system to the point of use at the customers' taps by a residual level of chlorine. A single source has treatment to reduce the amount of nitrates, which is elsewhere kept within acceptable limits by blending output from various sources where necessary. The smaller proportion of water from rivers and reservoirs has a more complex form of treatment. In addition to the processes used for underground supplies, clarification and filtration processes provide a similar high quality drinking water. Again, in all cases disinfection is maintained by a residual level of chlorine.

A leakage control initiative was introduced following privatisation in 1989 which has reduced water loss by 147 million litres per day. Since privatisation, Southern Water has had one of the best records with respect to water supply leakage among the Water and Sewerage Companies ("WaSCs"). Losses through leaks in its distribution system stood at 11.0% in 1999-00, compared to 26.0% just before the time of privatisation, with a target to achieve 10.9% by 2000-01. Southern Water monitors water quality through a programme in which samples are analysed regularly for both microbiological and chemical parameters. In 2000, 99.89% of water sampled passed the EU performance criteria.

Wastewater Business
Southern Water has 390 wastewater treatment works ("WTWs"), which treat wastewater pumped through 20,812 km of sewer by 1,975 pumping stations. WTWs provide various treatment types: primary, enhanced primary, secondary biological and tertiary. Under the Water Resources Act 1991, WTWs are granted consent by the Environment Agency ("EA") to discharge wastewater effluent to controlled waters. The conditions attached to each consent can cover quality, quantity and operational parameters as laid down in the "Standard Clauses" of the Discharge Consents Manual issued by the EA. The basis of the EA's policy is to maintain and improve water quality and the aquatic environment.

The disposal of sludge produced by WTWs is strictly controlled. Disposal to landfill is becoming restricted due to the lack of available local sites and all sludge disposed in this way is subject to a Landfill Tax. Disposal at sea ceased by December 1998. It is intended that the majority of the sludge produced at Southern Water's WTWs will be further processed to produce a soil conditioner which can be recycled and sold to the agricultural industry. The recycling of treated sludge to agricultural land is controlled by an EU directive. The sludge produced by Southern Water's WTWs amounts to 82,200 tonnes of dry solids per year.

As part of the treatment process to meet current bathing water standards, Southern Water has 20 marine treatment works and 30 long sea outfalls around the coastline of its region. In the 2000 bathing season, under the EU Bathing Water Directive, the EA tested 79 beaches in the Southern Water region. Under the directive, the EA takes at least 20 samples during the bathing water season (1 May to 30 September) at each identified bathing beach and compliance is assessed on the basis of tests for bacteria. In addition, tests are carried out for 19 other parameters. At least two samples are analysed for enteroviruses at those bathing waters that failed the mandatory coliform standards during 1999 (i.e. the previous year) or that failed coliform standards in 2000. Results may be published and posted by district councils on the beaches concerned. In the 2000 bathing season, only two beaches out of 79 failed the compliance tests. Capital schemes are in progress to reduce the likelihood of failures in future.

Investment Programme
In common with other WaSCs, Southern Water is managing a substantial investment programme for the period 2000 to 2005, estimated to be some £1.1 billion. This programme is largely driven by the EU Bathing Water Directive, the Urban Waste Water Treatment Directive ("UWWTD"), the increase in the volume of sludge due to implementation of the UWWTD, and the expectation of more stringent environmental constraints relating to sludge disposal on land.

The programme is dominated by completing the construction of 13 coastal WTWs as required by the EU Directives. There is also a substantial programme of improvements to a larger number of small inland wastewater treatment works. In addition, there are required regulations set by the Office of Water Services ("OFWAT"), the Drinking Water Inspectorate and the EA to maintain and improve the security and quality of service provided. These outputs include projects to address:

• above and below ground asset maintenance;
• water resources and security of water supply;
• reduced leakage and improved water pressure;
• drinking water quality;
• removal of flooding risk; and
• improvement of storm overflows on combined sewers.

Southern Water was granted implicit funding in the price determination, settled in 1999, via an allowed annual rate of return on the OFWAT estimate of investment of £1.1 billion. Southern Water's investment programme has therefore essentially been 'funded' up front. A key aspect of the group's business strategy is to seek to deliver all of the required regulatory outputs of the capital programme as efficiently as possible.

Competition
Following the Competition Act 1998, an opportunity exists to develop competition in the industry yet further, however, the procedures proposed for companies to use each other's infrastructure to supply water and wastewater services remain complex. Southern Water welcomes the further opening of the industry to competition and has taken an active role in developing a commercial framework for competition. A robust framework is essential to enable the benefits of competition to be realised, as has been demonstrated by the experience of the ScottishPower group in other deregulated markets, such as electricity and gas. Southern Water continues to promote the involvement of all market players, including the regulators, at an early stage in the belief that, under a properly developed fair competitive scenario, only initiatives that add value will prosper and that this provides the best chance of overall benefits exceeding costs. Southern Water is already looking at ways in which it might be able to expand its own customer base and business. Specifically, in 2000-01 it has established a Sales & Service Team to deliver such opportunities.

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Business Review

Other UK Businesses

Telecommunications
The ScottishPower group retains a controlling interest in its telecommunications subsidiary, Thus plc, following its flotation on the London Stock Exchange in November 1999. The group has supported Thus' investment in further network development, the integration of its business divisions and the reinforcement of its core management to complete the transition from a regional to a UK national operator, with a UK-wide network. As a customer focused and service driven company, Thus continues to focus on business markets where the greatest opportunities for growth lie and is now delivering accelerating revenues reflecting the concentration on key business sectors where it has a distinct advantage. Reflecting this focus on the business market, Thus has made arrangements for the disposal of non-core assets, principally its Interactive services division, which provides information and competition services to the consumer market.

The core of the Thus business is the supply of telecoms, Internet and call centre technologies. Thus now has the essential building blocks in place – national coverage, broad product range, innovation, quality and high calibre individuals capable of delivering results. With 5,779 km of optical fibre now in the ground, Thus has expanded its traditional Scottish and London base to include major commercial centres throughout the UK including Liverpool, Chester, Manchester, Warrington, Newcastle, Birmingham, Gloucester, Bristol, Reading, Swindon, Leeds and Middlesbrough. To gear up for increasing volumes and enhance quality and resilience, the network has been expanded to an additional three key US Internet Exchange points – Mae East, Mae West and Ameritech – giving the Internet services full East/West US connectivity. The international network both to the US and to Europe via Demon Netherlands maintains the Thus position as a tier 1 Internet Service Provider ("ISP") in this international network.

Already one of the UK's largest web hosts, Thus expanded the services offered in this area. Demon Server Hosting offers customers a dedicated server that can be administered remotely and is aimed at small and medium sized customers ("SMEs") that have outgrown services provided by virtual hosting and corporate customers looking for a stable, reliable and robust platform for hosting their intranets and extranets. With SMEs particularly in mind, Demon Powertrader, an e-commerce product, allows even inexperienced users to start trading on-line within hours. Managed Customer Premise Equipment ("CPE") enables SMEs and large corporates to pass responsibility for the installation, configuration, monitoring and management of routing equipment to Thus and will be developed to see CPE used in conjunction with new Internet Protocol ("IP") services such as IP virtual private networks and 'voice over data'.

The expansion of the network and the development of new capabilities has allowed Thus to expand the service provided to many existing customers and given enhanced capacity to bid for and win contracts.

Appliance Retailing
At 31 March 2001, the Appliance Retailing business sold domestic appliances and consumer electronics through 171 ScottishPower stores throughout the UK; 112 of these are located on out of town retail parks. Home delivery, in-home servicing and replacement of appliances for customers of selected insurance companies are among the additional services provided. Appliance retailing remains intensely competitive with established leaders, Dixons and Comet, joined by new entrants such as Tesco, Wal-Mart and emerging European-wide players, wielding increased supply-chain power. Consequently, the year ended 31 March 2001 was a challenging one for the appliance retailing sector with price deflation, price competition and rental cost growth impacting on profitability. A major programme to improve the quality of the property portfolio and involving the disposal of the majority of High Street stores is well advanced, leaving a more focused network of superstores. New store openings of nine have been at a lower rate than initially planned due to more rigorous assessment of opportunities.

Information Technology
Calanais, established in May 2000 as a 50:50 joint venture between ScottishPower and leading US computer services group SAIC, traded profitably through its first year, adding some 100 new staff to cope with developing business commitments. It is well ahead of target in delivering IT cost savings to the ScottishPower group. As a reflection of the intention to focus on core business activities, all of ScottishPower's shares in Calanais were sold to SAIC on 23 March 2001. The basic contract mechanisms under which services are provided to ScottishPower remain intact.

Contracting Services and Technology
In line with the outcome of the extensive business review of 1999, these non-core activities were successfully sold as going concerns during 2000-01.

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Business Review

Group Employees

US Business
PacifiCorp and its subsidiaries had 6,668 employees on 31 March 2001. Of these, 6,595 were employed by PacifiCorp and its mining affiliates and 73 were employed by PFS and other subsidiaries. As a result of the merger with ScottishPower, PacifiCorp developed and commenced 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, mainly through early retirement, voluntary severance and attrition.

Approximately 62% 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 and the United Mine Workers of America.

In the company's judgement, employee relations in PacifiCorp are satisfactory.

UK Business
ScottishPower and its UK subsidiaries had 15,313 employees, as at 31 March 2001. A breakdown of the number of employees employed in the group's main businesses is shown in Note 3b to the Group Profit and Loss Account .

In the infrastructure businesses, ongoing integration of Scottish and Manweb operations has been effectively completed and, in Southern Water, manpower efficiencies have been achieved. The group continues to benchmark for further efficiencies and reduced costs, which will include ongoing reduction in manpower numbers. However, such reductions were partly offset in 2000-01 by manpower growth within customer-facing businesses to gain new customers in the fully competitive market place. This growth has now peaked and is expected to reverse as the business continues to focus on core activities, achieving operating improvements and taking further advantage of technological advancements. Corporate services have remained relatively stable in manpower numbers since 1997-98 but the disposal of non-core businesses and outsourcing of certain functions have reduced overall UK employee numbers outside the energy businesses.

Approximately 46% of employees in the UK are union members, and 74% 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.

In the company's judgement, employee relations in the UK businesses are satisfactory.

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Business Review

Group Environmental Policy

Environmental Governance
It is now widely accepted that any responsible business with aspirations of continued growth and leadership must balance economic goals with the needs of the society in which it operates and the natural resources on which it depends. Climate change has emerged as a dominant sustainability challenge for all businesses, and is particularly acute for the energy sector. ScottishPower faces the task of developing an international vision within which the group can flourish and meet the business goal of creating sustainable value, despite widely differing stakeholder opinions on which environmental issues really matter.

For example, in the UK, policies to combat global climate change are paramount. The UK is committed to a voluntary target of 20% reduction in carbon dioxide ("CO2") emissions by 2010. Fiscal and regulatory incentives such as a Climate Change Levy and the new Energy Efficiency Commitment form key components of the UK Climate Change Programme to back up CO2 reduction targets. Although President Bush has rejected the Kyoto Protocol, the US remains concerned about global climate change and has indicated that it will bring forward alternative proposals. However, at a state level, much is actually being achieved to reduce CO2 emissions.

There are similar approaches to reducing emissions to air from fossil-fuel generation with tighter controls on air pollution driven by the continued implementation of the US Clean Air Act and, in the UK, by regulations such as the EU Ceilings Directive, the Large Combustion Plants Directive 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 US stakeholders.

Achieving the right balance is a significant business challenge which has been met by organising the skills and resources deployed in these different marketplaces within a common framework: but one which takes account of essential differences between the US and UK situations. The group's international environmental governance approach is based on arrangements which have worked well in the UK and which have been refined and tailored using the environmental management systems and mature operational controls within PacifiCorp. The company is committed to the highest standards of corporate governance. ScottishPower's structures and controls have been commended and recognised in awards such as the recent Utility Week Award for environmental management and the group's ranking as top utility and second place overall in the Financial Times/Business in the Environment corporate engagement survey of the FTSE 350 companies.

The main components of the group's international approach to environmental governance are as follows:

• the adoption of a common set of environmental principles and a consistent governance approach to ensure compliance with those principles;
• pro-active stakeholder engagement, including research, consultation and the work of the Environment Forum, which introduces expert external opinion through independently facilitated meetings that promote understanding of the views of key opinion formers in the sector;
• assessment of cross business risk through the group Environmental Policy Advisory Committee, which advises on the development of environmental policy and strategy, often through issue-focused working groups;
• annual business risk assessments, conducted this year by independent consultants OXERA;
• active environmental management and operational control by means of environmental management systems;
• measurement of Key Performance Indicators linked to significant sustainability parameters;
• accounting for performance to stakeholders in the annual Corporate Environment Report; and
• an independent third party review of environmental governance arrangements.

All group businesses are required to implement an environmental management system equivalent to the international standard 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 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 ScottishPower'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 AAA–, where AAA+ is the highest possible and C- is the lowest. ScottishPower has a robust process of risk assessment operating comprehensively across the business and subject to internal review and external scrutiny. The most recent external review was conducted by OXERA and concluded that the group had an excellent knowledge of environmental risk and managed such risks with a high level of care and prudence.

ScottishPower's vision and framework for action involves achieving lower levels of CO2/kWh across the generation portfolio to combat global climate change, backed up by a range of measures to achieve this overarching goal. 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, have been implemented.

In both the US and the UK, energy and environmental policy and regulation are inextricably linked. Fiscal instruments will drive moves towards more sustainable forms of generation. The opening up of markets to competition will also play an increasing role in providing opportunities for new renewable technologies, balanced against the social requirement of security of supply through diversity of fuel mix. The ScottishPower group 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 and clean air impact of its generation plants and working with customers to implement energy efficiency programmes. The Green Energy and Green Sources tariffs allow UK domestic and business customers to support investment in renewables. During 2000-01, similar environmentally friendly options were introduced under the Blue Sky Energy tariff launched by PacifiCorp.

Climate Change
Climate change has become the single most important environmental issue in the UK, which has prompted the Government formally to adopt the Climate Change Programme. This is a basket of various tax and financial incentives aimed at meeting the Government's commitment to reduce emissions of CO2 to below 1990 levels by 2010. These measures include the Climate Change Levy, an industrial and commercial energy tax, the new Energy Efficiency Commitment contained in the Utilities Act and the proposed introduction of a UK carbon trading regime later in 2001. There is therefore a comprehensive range of instruments in place which will drive reductions in CO2 in the UK electricity sector.

In the US, there is awareness of the issue of global climate change. However, there is some concern about the measures proposed in the Kyoto Protocol and about its rejection by the Bush administration. The approach to carbon reduction has focused on the appropriate use of carbon sinks and offsets, such as new forestry planting and reducing CO2 through a trading programme. Differences in approach to international trading led to the collapse of the November 2000 summit in The Hague. However, the State of Oregon is actively funding energy conservation and investment in renewables through the Public Benefits Charge, and some direct state requirements make it necessary for new developments to offset part of their emissions as a siting condition. It is clear that long term CO2 reductions will be supported in the US, providing they are allowed through rate recovery or via market instruments such as emissions trading or green tariffs.

The group's commitment to renewables will increasingly help to improve financial performance and meet environmental obligations. In the US, PacifiCorp is about to bring on-stream the world's largest windfarm. It is on the Oregon-Washington State border and has 450 turbines generating an output of 300 MW, enough power for 70,000 homes. An overall ScottishPower investment of £100 million, combined with a strategy of developing a further 480 MW has made the group one of the leading UK operators. PacifiCorp aims to build or purchase 1,000 MW of new renewables by 2005, becoming the leading supplier of new renewables in the western US.

Recent acquisitions of gas-fired plant, combined with windfarms coming on stream, will help meet the goal of reducing CO2/kWh across the generation portfolio in the UK. Major commitments to renewables in the US will have a similar effect. PacifiCorp has developed the innovative 484 MW Klamath Falls co-generation plant, due on-line in July 2001. This award winning plant will be one of the cleanest plants in the US in terms of net greenhouse gas emissions, backed up by a programme of carbon offsets including methane recovery, US reforestation and solar electrification in developing countries.

Air Quality
In both the US and UK, concern to improve local air quality, soil and water acidification and improve visibility, particularly in wilderness areas, is driving tightening controls on air emissions from fossil-fuelled power plants. Therefore, the trend in both the US and UK is for increasingly strict air emission requirements to be enforced, driving investment in abatement technology to clean up coal-fired generation.

In the US, the sulphur dioxide ("SO2") trading allowed for by the Clean Air Amendments has led to cost-effective reductions in emissions. However, other issues such as photochemical smog and visibility have led to new requirements for further reductions in oxides of nitrogen ("NOx") and SO2. In response primarily to urban smog issues, generators in the eastern US are now being compelled by air regulators to install controls which go beyond low NOx burners, such as Selective Catalytic Reduction.

PacifiCorp is reliant on low-sulphur coal and, with the further addition of scrubbers, PacifiCorp plants (both owned and/or operated) have emissions rates 70% below the national SO2 average and 18% below the national NOx average. Additional reductions in SO2 of up to 40% (or approximately 45,000 tons) will be required over the next 15 to 20 years to address possible impairment of visibility at National Parks. NOx requirements to address visibility are in the process of being defined. While aggressive emissions reductions are planned, PacifiCorp is working with stakeholders to define a path forward that will provide more comprehensive reductions. Uncertainty regarding future air quality requirements stalls investment in emissions controls and hinders the development of new plants. Beyond compliance, PacifiCorp will pursue permitting changes that lead to cost-effective emission reductions with clear environmental benefits, while allowing for the on-going efficient operation of its thermal generating plants for the next 15 to 20 years.

The UK will tighten SO2 emissions significantly by 2010 in response to the EU Ceilings Directive, driving investment in flue gas desulphurisation ("FGD") and scrubbing. The combined effects of the revised Large Combustion Plants Directive and the Integrated Pollution Prevention and Control Directive will tighten emission levels considerably from 2007 onwards, although the final position on NOx emissions is not determined.

ScottishPower has gradually implemented a programme to optimise the thermal efficiency of Longannet and Cockenzie coal-fired power stations and invested in technology to reduce the emissions of SO2 and NOx. It will continue to look for opportunities to invest in increased thermal efficiency in both plants, if cost- effective, and has now agreed a programme for FGD at Longannet which should significantly reduce SO2 further. The gas re-burn technology introduced at Longannet has won both a Queen's Award for Enterprise (in Sustainable Development) and an Institute of Chemical Engineers' prize.

Energy Saving
Energy efficiency programmes are essential tools in avoiding the use of peaking plants and the over development of new supply. In the western US, demand side management measures are crucial to help cope with immediate shortages of generating capacity. In addition to longer term energy savings, PacifiCorp is actively managing customer demand during summer and winter peak periods to limit market exposure to high prices and to protect customers from higher costs. In the UK all PES Licence Holders, such as ScottishPower, are obliged to comply with levels of domestic energy saving under the Energy Efficiency Standards of Performance regime. ScottishPower has regarded this obligation positively and has performed consistently ahead of targets, both saving energy and targeting low income groups in particular for support.

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Group Research and Development

The group supports research into development of the generation, transmission, distribution and supply of electricity and continually seeks more innovative and cost effective methods of carrying out its water and wastewater activities. It also continues to contribute, on an industry-wide basis, towards the cost of research into electricity utilisation, distribution developments and water purification and wastewater treatment. In financial years 2000-01, 1999-00 and 1998-99, the group's expenditure on research and development was £4.2 million, £5.5 million and £5.3 million, respectively.

The group's policy is to charge research and development expenditure to the profit and loss account as it is incurred.

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Description of the Group's Property

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

PacifiCorp owns 52 hydro-electricity generating plants and has an interest in one additional plant. These have an aggregate nameplate rating of 1,078 MW and plant net capability of 1,137 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 of 33 MW and plant net capability of 33 MW. Table 1 sets out key aspects of PacifiCorp's existing generating facilities.

These generating facilities are interconnected through PacifiCorp's own transmission lines (see Table 6 ) or by contract through the lines of others. Substantially all generating facilities and reservoirs located within the Pacific Northwest region are managed on a co-ordinated 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 . 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.

UK Businesses
The properties consist of generating stations, transmission and distribution facilities, water supply and wastewater treatment facilities, appliance retailing facilities and certain non-operational properties in which the group holds freehold or leasehold interests.

The group owns seven power stations in Scotland, five of which are operational, and two in England. The group also owns three windfarms in Northern Ireland, three 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 for further details of generation assets.

As of 31 March 2001, the group's UK transmission facilities included approximately 3,850 circuit km of overhead lines and 250 circuit km of underground cable operated at 400 kV, 275 kV and 132 kV. In addition, the group's 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 9 for further details.

Southern Water has freehold and leasehold interest covering a total of approximately 10,000 acres of land. Of such land, an aggregate of approximately 9,800 acres are specialised properties, consisting chiefly of the raw water storage reservoirs with surrounding land, water and wastewater treatment works and pumping stations listed in Table 13 , Table 14 and Table 15 . Approximately 95% of the above-ground water supply and wastewater assets are on land in Southern Water's freehold ownership including the assets listed in Table 13 , Table 14 and Table 15 , with the remainder being located on land subject to long-leasehold.

As at 31 March 2001, the group operated 171 Appliance Retailing outlets, 162 of which were leased, and nine group owned. The business also leases three large distribution depots, Castleford, Mossend and Rugby together with two smaller outbases and these properties are generally held on 20 to 25 year leases.

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Business Review

Group Charitable and Political Donations

During 2000-01, donations made for charitable purposes by the ScottishPower group totalled £2.5 million. £10.9 million of community support activity comprising charitable donations, community investment and commercial initiatives given in cash, through staff time and in-kind donations was undertaken by the group's US and UK operations.

It has been the company's practice to make statements in its Annual Report that no money has been given by the company for political purposes, and such a statement is again made in relation to the year ended 31 March 2001. Such statements have been made in compliance with rules contained in the Companies Act 1985 relating to the relevant financial years. However, with effect from 27 July 2001, the date of the company's Annual General Meeting in 2001, the company will be subject to new rules governing donations to political parties and organisations and other political expenditure by reason of the Political Parties, Elections and Referendums Act 2000, which came into force on 16 February 2001. The foregoing statement does not relate to donations made or expenditure incurred within the meanings set out in this Act. A resolution will be put to shareholders at the Annual General Meeting seeking approval for such donations and expenditure, as now defined by this Act; further details may be found in the Notice of Meeting.

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Business Review

Description of Legislative and Regulatory Background

As a public limited company ("plc"), Scottish Power plc is subject to the UK Companies Acts and, following the acquisition of PacifiCorp, Scottish Power plc also registered as a holding company under the US federal Public Utility Holding Company Act of 1935 ("1935 Act"), which is administered by the US federal Securities and Exchange Commission ("SEC"). Bills have been introduced to repeal this legislation in each of the last several Congresses, but to date have failed to pass. Until the 1935 Act is repealed, Scottish Power plc and PacifiCorp and other subsidiaries will be subject to regulation unless specific subsidiaries or transactions are otherwise exempt by SEC rules or orders. Scottish Power UK plc, and its subsidiaries (including Manweb, Southern Water and Thus) are exempt because Scottish Power UK plc is an exempt foreign utility as defined in the 1935 Act. While there are increased administrative burdens imposed by 1935 Act regulation, ScottishPower does not believe this regulation will have a harmful effect on ScottishPower or its subsidiaries.

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 registered holding company level and has no effect on PacifiCorp.

ScottishPower's UK operations are subject to such European Union ("EU") Directives as HM 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, which came into effect from 1 March 2000) and also to the provisions of the Utilities Act 2000 ("Utilities Act"). The Utilities Act requires a new legal framework for utility licences based on standard, UK-wide conditions and, taken together with requirements of the Department of Trade and Industry ("DTI") and licence changes introduced by the Regulators, obliges the group to restructure its UK operations into a series of separate limited companies, each a wholly owned subsidiary of ScottishPower UK plc. This process is being implemented in line with a DTI timetable and is due to be completed by April 2002. Whilst the group has to make these changes to its structure to comply with statutory and regulatory pressures, the UK business of ScottishPower continues in the ordinary course and the restructure will not interfere with the day-to-day conduct of employees' duties, nor will it alter their terms, conditions and benefits.

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

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US Business Regulation

PacifiCorp is subject to the jurisdiction of the public utility regulatory authorities 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.

Relicensing of hydro-electric projects
PacifiCorp's hydro-electric portfolio consists of 53 plants that include 87 generating units with a total capacity of nearly 1,100 megawatts ("MW"). Of the installed capacity, 97% is regulated by 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 an extremely political and public regulatory process that involves controversial resource issues. In the new licences, 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 tribes have mandatory conditioning authorities that give them significant influence and control in the relicensing process. It is extremely difficult to determine the economic impact of these mandates, but capital expenditure and operating costs are expected to increase in future periods while generation 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.

Recovery of the Excess Costs of the Hunter Outage
Subsequent to filings made on 1 November 2000, seeking deferred accounting treatment for net power costs that varied from costs included in determining retail rates in Utah, Oregon, Wyoming and Idaho, PacifiCorp's Hunter power plant in Utah experienced a failure of a 430 MW generation unit. Since the commencement of the outage, the cost of power purchases to replace the output of the Hunter unit exceeded that unit's costs included in current rates. The Oregon, Wyoming and Idaho deferred accounting filings encompassed all power cost variances from the level assumed in rates since 1 November 2000, including costs to replace lost generation resulting from the Hunter outage, and the Utah filing was effectively amended by stipulation to include only the variances associated with the Hunter outage. Hunter deferred accounting was adopted by the Utah Public Services Commission ("PSC") effective 24 November 2000 and by the Wyoming PSC on 30 November 2000. Deferrals were also agreed in Oregon and Idaho on 23 January 2001 and 12 February 2001, respectively. PacifiCorp is reviewing its options in Washington, where it agreed to a five-year rate plan in June 2000, before purchased power costs significantly increased, and is looking at ways to reopen that rate plan and either defer, or obtain rate inclusion of, power costs that vary from the level in current Washington rates.

Regional Transmission Organisation ("RTO")
PacifiCorp, in conjunction with eight other companies, is involved in a voluntary effort to form an RTO, named RTO West, in support of FERC Order 2000, which requires all public utilities that own, operate or control interstate electricity transmission to file a proposal for an RTO. The nine members of RTO West will be Avista Corporation, BPA, Idaho Power Company, 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 about 30,000 miles of the 50,000 miles of transmission line owned by the entities. On 16 and 23 October and on 1 December 2000, the members made filings addressing structural, operational and contractual issues associated with the RTO formation. On 25 April 2001, FERC accepted the key components of these filings, including the governance structure, scope and configuration. FERC suggested that RTO West could serve as an anchor for the ultimate formation of an RTO encompassing the entire Western System Coordinating Council ("WSCC"). Because of the continuing development, PacifiCorp cannot currently quantify the impact that the RTO formation will have on its future operations.

Demand Side Management
In December 2000 and January 2001, PacifiCorp filed for Pilot Energy Exchange Service programmes in Utah, Oregon, Wyoming, Washington and Idaho. These programmes are an optional, supplemental service that allows participating customers an opportunity to reduce voluntarily electricity usage in exchange for a payment at times and at prices determined by PacifiCorp. The customer must execute an agreement prior to being allowed to receive service under the programme. PacifiCorp expects these programmes to be an economic alternative to paying higher market prices, by reducing the system-wide demand for electricity. In March 2001, PacifiCorp submitted proposals to expand the programmes to all customers of 1 MW and greater in Utah, Oregon, Wyoming, Washington, and Idaho. The exchange had achieved over 9,500 megawatt hours ("MWh") of load curtailment by 31 March 2001 and is expected to grow as the customer base expands. In March 2001, PacifiCorp also filed and received regulatory approval to implement voluntary curtailment programmes for irrigation customers in Oregon and Washington. Similar filings were submitted in Utah and Idaho and are under regulatory review. PacifiCorp filed for approval of Residential Usage Incentives in all states it serves in April 2001. If approved, the incentives would provide a 20% credit on monthly bills in June, July, August and September 2001 for residential customers who reduce their monthly power usage from the corresponding month one year ago by 20%. PacifiCorp believes this programme will set clear and simple targets for customers to receive benefits if they conserve energy.

Proposed Restructuring
On 1 December 2000, PacifiCorp filed requests with the utility commissions in Utah, Oregon, Wyoming, Washington and Idaho to change the way in which PacifiCorp is regulated. A similar filing is planned for California. The proposed plan would change PacifiCorp's legal and regulatory structure and result in the creation of six state electricity distribution companies, a generation company and a service company, all subsidiaries of a new holding company. The proposal is designed to provide a permanent allocation of generation benefits and costs among states that will allow each to pursue the regulatory policies they deem appropriate without affecting customers in other states or treating shareholders unfairly. Approval for these proposals must be obtained from the utility commissions in Utah, Oregon, Wyoming, Washington, Idaho and California, as well as from FERC and the SEC. This process is expected to take more than a year.

Competition
PacifiCorp believes that the regulatory initiatives that are underway in each of the states it serves may eventually bring competition for electricity generation services. This change in the regulatory structure may significantly affect PacifiCorp's future financial position, results of operations and cash flows. PacifiCorp intends to seek regular price increases to the extent it earns less than its allowed rate of return.

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

Utah
PacifiCorp received an order from the Utah Public Service Commission ("UPSC"), effective on 25 May 2000, authorising increased prices in Utah resulting in additional annual revenues of $17 million. On 12 January 2001, PacifiCorp filed a request with the UPSC for an increase in electricity prices for its customers in Utah. This request encompasses normalised power costs that varied from the level assumed in Utah rates based on the 12 months ended 30 September 2000 test year and did not include those power variances associated with the Hunter outage. If approved, the request would increase prices by approximately 19.1% overall, or $142 million. Concurrently, PacifiCorp filed a separate emergency petition for interim relief asking that the increase become effective on 22 January 2001. On 2 February 2001, the Commission granted an interim rate increase of $70 million, effective on 2 February 2001, subject to refund if the final rate order does not provide for at least this level of recovery.

The 2001 Utah legislative session passed a bill that repealed a 2000 Utah legislative session bill that could have significantly changed the way in which power providers are regulated in the state. However, the legislature also passed a bill extending the

life of a legislative task force created in 1997 to study restructuring issues. The bill authorises this task force to meet as often as twice a month to prepare legislation to implement an electricity restructuring plan for presentation and consideration in the 2002 legislative session, unless it is not in Utah's best interest to do so. PacifiCorp intends to seek recovery of all its prudent costs, including stranded costs, in the event of deregulation. However, due to the current lack of definitive legislation, PacifiCorp cannot predict whether it will be successful.

Oregon
Under an order from the Oregon Public Utilities Commission ("OPUC") effective on 1 October 2000, PacifiCorp increased prices in Oregon resulting in annual additional revenues of $14 million. In addition, new rates which took effect from 1 July 2000 through an annual adjustment as part of the alternative form of regulation process previously authorised in Oregon, increased annual revenues by approximately $3.7 million net of costs mandated by the OPUC.

On 23 March 2001, PacifiCorp filed a request with the OPUC for approval of a $43 million, or 24.5%, increase to recover higher power costs for the months of May, June and July 2001. The $43 million increase is the difference between net power costs currently included in rates and what PacifiCorp expects to incur in the period 1 May to 31 July 2001. The increase would be applied to all customer bills on a cents per kWh used basis, and would remain in effect until 1 August 2001, when new power costs are expected to be set as part of a previously filed rate case. PacifiCorp also requested permission to implement a power cost adjustment mechanism to track changes in net power costs.

During 1999, legislation ("SB 1149") was enacted in Oregon that requires competition for industrial and large commercial customers of both PacifiCorp and Portland General Electric Company by 1 October 2001. Under the legislation, PacifiCorp is required to unbundle rates for generation, transmission, distribution, and other retail services, and offer residential customers a cost-of-service rate option, and a portfolio of rate options that includes new renewable energy resources and market-based generation. SB 1149 authorises the OPUC to make decisions on a variety of important issues, including the method for valuation of stranded costs/benefits. The OPUC may provide incentives for divestiture of generation assets or the functional separation of such assets. Generation asset divestiture is not mandated and is solely at PacifiCorp's discretion. Transition charges may be included in the direct access, portfolio rate option, and cost-of-service rates. SB 1149 requires the OPUC to report to the Oregon state legislature by 1 January 2003 as to whether residential electricity customers would benefit from direct access.

On 2 October 2000, PacifiCorp filed its plans to implement the requirements outlined by SB 1149 and subsequent commission rules. On 1 November 2000, PacifiCorp filed the unbundling information required under SB 1149 rules and requested a related $160 million in increased revenues. On 1 December 2000, PacifiCorp filed a resource plan to address the manner in which it proposes to use its generation resources under SB 1149. This Resource Plan presents the estimate of the value of PacifiCorp's generating facilities. This valuation is based on various assumptions, including future electricity prices and cost estimates for compliance with existing and anticipated air quality regulations impacting PacifiCorp's thermal generation, as well as the estimated costs associated with relicensing PacifiCorp's hydro-electric facilities. PacifiCorp's preliminary analyses indicate that the after-tax present value of the air quality and hydro-electric costs over the projected useful life of the thermal plants, and the term of the licences in the case of the hydro-electric licences, could exceed $1 billion, predominantly in increased capital expenditure. The final outcome is dependent on a variety of factors, including the actual terms and applicability of existing and anticipated environmental laws and regulations, the costs associated with lost generation, developments in pollution control technologies, and the actual terms and conditions of any new hydro-electric licences. The ultimate impact of these compliance costs on PacifiCorp will depend on the regulatory treatment of such costs, whether PacifiCorp elects to sell or abandon facilities rather than make the required capital expenditure, and numerous other factors, many of which are beyond PacifiCorp's control.

In February 2001, PacifiCorp made its Oregon Resource Plan Supplemental Filing. This filing addressed the potential rate impacts and transition charges and credits associated with implementation of the resource plan options and also proposed that the preferred plan for implementing direct retail access in Oregon would involve the restructuring proposals discussed above under " Proposed Restructuring " (see page 21). The Commission has adopted a temporary rule extending the decision date on the Resource Plan from 1 April 2001 to 1 September 2001.

On 3 January 2001, the OPUC adopted public purpose rules as required by SB 1149. The rules require electricity utilities and suppliers that provide electricity services to direct access consumers to collect public purpose charges equal to 3% of the total revenues for electricity services, distribution, ancillary services, metering and billing, transition charges, and other types of costs that were included in electricity rates on 23 January 1999. PacifiCorp will continue to participate in the OPUC proceedings to establish the rules and procedures that will implement the new law.

Wyoming
On 25 May 2000, PacifiCorp received an order from the Wyoming Public Service Commission ("WPSC") authorising an increase in prices resulting in increased annual revenues of $11 million, subsequently adjusted to $12 million under WPSC approval effective 19 July 2000. On 18 December 2000, PacifiCorp filed a request with the WPSC for an increase in electricity prices of about 3.4% overall, or $9 million to be effective no sooner than 12 months after the date of the order of the previous case, that is, from 25 May 2000.

Washington
On 9 August 2000, PacifiCorp received an order from the Washington Utilities & Transportation Commission ("WUTC") which authorised PacifiCorp to increase rates by 3% on 1 September 2000, 3% on 1 January 2002 and 1% on 1 January 2003. On 25 October 2000, the WUTC approved PacifiCorp's application for a system benefits charge to recover costs associated with funding energy efficiency programmes: PacifiCorp will collect approximately $2.8 million per year until 31 December 2002.

Idaho
The 1980 Pacific Northwest Electric Power Planning and Conservation Act provided for, among other things, the Residential Exchange Program to provide the residential and small farm customers of northwest investor-owned utilities with a share of the benefits associated with the Federal Columbia River Power System. The Residential Exchange Program will expire on 30 September 2001. It will be replaced by a new programme established by the Bonneville Power Administration ("BPA") under its Power Subscript Strategy. On 30 October 2000, PacifiCorp and the BPA executed a 10-year settlement agreement that replaced the Residential Exchange Program. This settlement will be effective from 1 October 2001 and is expected to provide PacifiCorp's residential and irrigation customers in Oregon, Washington and Idaho with annual benefits equalling $76 million during the first five years of the agreement. These benefits pass through to customers and do not impact PacifiCorp's earnings.

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Business Review

Structure of the Electricity Industry in the UK

The UK electricity industry, which was restructured in March 1990 to introduce competition into the generation and supply of electricity, consists of the following:

Generation
The production of electricity at power stations.

Transmission
The bulk transfer of electricity across a high voltage transmission system.

Distribution
The transfer of electricity from the high voltage transmission system and its delivery, across local low voltage distribution systems, to customers.

Supply
The bulk purchase of electricity by suppliers and its sale to customers, with the associated customer service activities, including sales and marketing, billing and income collection.

The UK has three distinct geographical systems: Scotland, England & Wales and Northern Ireland, each with a different commercial framework. The systems of Scotland and England & Wales are interconnected, and construction of a link between Scotland and Northern Ireland has commenced with commercial operation anticipated from winter 2001-02. A series of regulatory reviews and licence modifications is in progress which will, over a period of years starting in summer 2001, introduce a more standardised, UK-wide structure of licence conditions and trading arrangements to which all companies will have to conform.

In each of Scotland and England & Wales, the electricity industry is regulated under the Electricity Act 1989 ("Electricity Act") and the Utilities Act by the Secretary of State for Scotland or the Secretary of State for Trade and Industry, as applicable (collectively, "Secretary of State"), and by the Gas and Electricity Markets Authority ("Authority"). See " Regulation of the Electricity Industry in the UK ".

Electricity Industry Structure in Scotland
The electricity industry in Scotland is principally composed of two vertically integrated companies, ScottishPower and Scottish & Southern, each generating, transmitting, distributing and supplying electricity within their respective authorised areas. A third, British Energy, is primarily a generator, selling all the electricity it generates at its two nuclear power stations in Scotland to ScottishPower and Scottish & Southern under the Nuclear Energy Agreement ("NEA"). In addition, there are a number of other companies supplying electricity competitively to customers in Scotland, of which the most significant is British Gas Trading.

Throughout the bulk of 2000-01, the two integrated companies were also obliged to sell wholesale electricity on request to second-tier suppliers in Scotland at a price capped at the England & Wales Pool price. Since the introduction of the New Electricity Trading Arrangements ("NETA") for England & Wales on 27 March 2001, interim arrangements have been put in place pending completion of the current review by the Authority of longer term Scottish trading arrangements, together with the arrangements for access to the interconnector, the restructuring contracts, and other aspects of the market in Scotland. This review of British Electricity Trading and Transmission Arrangements ("BETTA") has the objective of promoting competition and aligning the trading arrangements in Scotland with the new arrangements in England & Wales. See " Electricity Industry Structure in England & Wales – Generation and Trading".

Generation – ScottishPower and Scottish & Southern generate electricity from their own portfolios of power stations. In addition, the companies are obliged, under the NEA, to purchase the entire output from British Energy. A number of further contractual relationships exist between the two companies, which involve the sharing of coal-fired, dual oil and gas-fired, and conventional hydro generating capacity, by allocating part of the capacity of certain generating stations operated by one company to the other company. See " UK Division – Generation Portfolio " for further discussion of these contractual arrangements. Currently, there exists a surplus of generating capacity in Scotland which enables the companies to sell electricity to England & Wales through the interconnector. Subject to the outcome of the BETTA review, the quantity of these sales is expected to increase as the capacity of the interconnector is enhanced.

Transmission – The transmission systems of ScottishPower and Scottish & Southern are each made up of a network comprised of overhead lines, underground cables and associated equipment, operating at either 275kV or 132 kV and, in the case of ScottishPower, 400 kV. This network connects the generating stations and distribution entry points operating at, or below, 33 kV. ScottishPower's transmission system is connected to the National Grid in England & Wales by the interconnector. Both companies have access to this link which enables the companies to export and import electricity from England & Wales. The available capacity of the interconnector at any time depends on a number of variable factors (e.g. the secure thermal rating of the interconnector circuits and the pattern of scheduled generation on either side of the border). In 2000-01, the average capability of the interconnector was 1,367 MW. The Authority is currently reviewing BETTA, which appears likely to lead to 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.

Distribution – The distribution systems are each made up of a network of overhead lines and underground cables, operating at voltages ranging from 33 kV to 0.23 kV. The distribution voltages and equipment used are determined by end users' requirements and their location and by the relative economics of transferring electricity at different voltages. To ensure competition in generation and supply activities, the companies are required to provide open access to their transmission and distribution networks on a non-discriminatory basis.

Supply – The supply businesses of ScottishPower and Scottish & Southern purchase electricity, primarily from their own respective generation businesses, for sale to customers both within their first-tier home areas and in each other's area. Other second-tier suppliers (see " The Licensing Regime ") generally purchase their electricity either from ScottishPower or Scottish & Southern at a price which is capped at the England & Wales price, but may also purchase electricity from independent generators or across the interconnector from England & Wales.

Electricity Industry Structure in England & Wales
In England & Wales, electricity is produced by generators, the largest of which are British Energy, PowerGen, Innogy, AES, EdF and TXU Europe. Electricity is transmitted through the National Grid transmission system by National Grid Company ("NGC") and distributed by the 12 Public Electricity Distributors ("PEDs"), one of which is Manweb, in their respective authorised areas. Most customers are currently supplied with electricity by their local Public Electricity Supplier ("PES"), of which Manweb is one, although there are other suppliers holding second-tier supply licences, including other generators and PESs, who can also compete to supply customers.

Generation and Trading – Since privatisation, virtually all electricity generated in England & Wales has been sold by generators and bought by suppliers through the Pool, a mechanism established on industry privatisation in 1990 for bulk trading of electricity in England & Wales, in which ScottishPower and Scottish & Southern participated by exporting or importing via the interconnector. Wholesale electricity prices were set by the Pool daily for each half hour of the following day, based on the bids of the generators and a complex set of calculations matching supply and demand and taking account of system stability, security and other costs. Because Pool prices tended to be volatile and difficult to predict, generators and suppliers often entered into bilateral arrangements, such as contracts for differences, to provide a degree of protection against such fluctuations.

These arrangements applied throughout the bulk of 2000-01 but, following consultation and industry-wide system development, NETA took effect (some 18 weeks later than originally intended) on 27 March 2001. NETA replaced 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. The new arrangements remove the single Pool price at which all generation in any half-hour was previously bought and sold. Instead, all generators now have to find buyers for their output, by offering them competitive prices, and all suppliers have 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 thus leads to more cost-reflective prices and more effective management of risk.

Transmission – NGC owns and operates the high voltage 275 kV and 400 kV electricity transmission system in England & Wales, also known as the National Grid. NGC has a statutory duty to operate a non-discriminatory policy, both in the day-to-day administration of the system and in the provision of access to the transmission network.

Distribution –The distribution businesses of the PEDs operate and maintain the assets which carry power from grid supply points to individual customers within their service areas. This involves a network of overhead lines, underground cables, switches and transformers operating at voltages ranging from 132 kV down to 0.23 kV in residential premises. To ensure competition in supply and generation of electricity, the PEDs are required to provide open access to their distribution networks on a non-discriminatory basis.

Supply – The supply business covers the bulk purchase of electricity and its selling on to customers. PESs can supply customers within their home areas and holders of second-tier licences, subject to meeting certain requirements, can supply any customer. Second-tier licences are held by all the PESs, Innogy, PowerGen, British Energy, ScottishPower, Scottish & Southern, British Gas Trading and some 12 other new suppliers.

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Business Review

Regulation of the Electricity Industry in the UK

The UK electricity industry is regulated under the provisions of the Electricity Act and the Utilities Act. The Electricity Act provided the basis for the restructuring of the electricity supply industry ("ESI") in England & Wales and in Scotland in 1990, including the introduction of price regulation for transmission and distribution and of competition in supply and generation. The Utilities Act introduced a new principal objective for regulators to protect the interest of customers, wherever appropriate by promoting effective competition, having regard to the need to ensure that licence holders are able to finance their functions. The Utilities Act also required electricity distribution and supply to be separately licensed and provided the legal framework to facilitate the introduction of new electricity trading and transmission arrangements. It also enabled the electricity and gas regulators to be merged as the Gas and Electricity Markets Authority, established new independent consumer councils and provided powers for Government Ministers to give statutory guidance on social and environmental issues and set energy efficiency targets and renewables obligations.

Regulation of the ESI
The Electricity Act provided for the appointment of the Director General of Electricity Supply ("DGES") by the Secretary of State. The Utilities Act transferred the functions of the DGES to the Authority and provided for the appointment of a Chairman and other members of the Authority by the Secretary of State. The Chairman of the Authority holds office for renewable periods of five years and is the Managing Director of Ofgem (Office of Gas and Electricity Markets). 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 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 in the generation, transmission, distribution or supply of electricity under the Fair Trading Act 1973 and certain functions relating to anti-competitive conduct under the Competition Act 1980 and the Competition Act 1998 ("Competition Act"). The Authority also manages UK compliance with the European Community Liberalisation Directive, which is concerned with introducing competition in generation and supply and non-discriminatory access to transmission and distribution across the EU.

The Licensing Regime
The Electricity Act prohibits the generation, transmission or supply of electricity to any premises unless authorised by a licence or exemption. Licences were granted for generation, transmission, public electricity supply and second-tier supply. Under the electricity privatisation regime, England & Wales was divided into 12 PES franchise areas, and Scotland into two additional PES franchise areas, for the purposes of electricity supply and distribution. Each of the 14 PES licences permits its holder to supply electricity to any premises within its home area (first-tier licence). Electricity suppliers which are not the PES licence holder for that home area are known as second-tier suppliers and have second-tier supply licences (second-tier licence).

In order for a second-tier licence holder to supply a "designated customer" (being a residential customer or a customer requiring less than 12,000 kWh per year) in the home area of a PES, the second-tier licence holder must issue a designated supply notice to Ofgem, and have its codes of practice (statements of intent about how the supplier will interact with customers) approved by Ofgem. Both ScottishPower and Manweb comply with this requirement.

The Utilities Act requires separate licensing of the 14 PESs' distribution businesses, introducing PEDs which, in order to ensure competition in the supply and generation of electricity, are required to provide open access to their distribution networks on a non-discriminatory basis. In order to implement the European Community Liberalisation Directive, Ofgem has drafted licence changes designed to ensure the managerial and operational independence of the ScottishPower and Scottish & Southern transmission businesses and to ensure confidentiality of information in both the transmission and the distribution businesses.

Under the draft PED licences, each PED licensee will distribute electricity for second-tier suppliers whose customers are within that PED's authorised area, as well as for the PES supply business serving the area. Charges for distribution will be made to the PES licensee or to second-tier suppliers as appropriate. Each PED licensee will be required, among other duties, to develop and maintain an efficient, co-ordinated and economical system of electricity distribution and to offer terms for connection to, and use of, its distribution system on a non-discriminatory basis. Each PED licence will require the PED licensee to plan and develop its distribution system to a standard not less than that previously applicable within the nationalised electricity supply industry and to report annually to the Authority giving details of the performance of the licensee in maintaining distribution security, availability and quality of service during the previous financial year.

ScottishPower is licensed under the Electricity Act to generate electricity, transmit electricity within its authorised transmission area, and distribute and supply electricity within its authorised distribution and supply area. This licence (a "Composite Licence") regulates each of its generation, transmission, distribution and supply businesses and certain other related aspects of its activities. In addition, it has second-tier licences which authorise it to supply electricity to customers located outside its authorised supply area. Manweb is licensed under the Electricity Act to distribute and supply electricity within its authorised distribution and supply area pursuant to its PED/PES licences. Manweb also holds second-tier licences which authorise it to supply electricity to users located outside its authorised area.

Separation of Businesses – Following the passage of the Utilities Act and in line with licence modifications proposed by the DGES in December 1999, modifications to the group's PES licences came into force on 1 April 2000. These start the implementation of the new legal framework for electricity licences based on standard, UK-wide conditions provided for by the Utilities Act. This means that the current composite licensing situation, which has enabled Scottish Power UK plc to operate as a single company owning each of the separate registered businesses, will come to an end and will be replaced by individual licences for Generation, Transmission, Distribution and Supply. As a result of the stringent nature of the new licence requirements on confidentiality of information and independence, Ofgem has granted temporary relief on a number of obligations, subject to the implementation of a Business Separation Plan. Actions taken to fulfil the obligations set out in the Business Separation Plan include:

• appointing an external Compliance Officer;
• establishing a high level Compliance Steering Group;
• developing implementation project teams within the businesses to deliver the plan; and
• establishing a separate Distribution Call Centre.

Progress of the Business Separation Plan is monitored by the Compliance Officer. In conjunction with the Steering Group, regular updates are reported to Ofgem and it is anticipated that the plan will be fully implemented before April 2002, the expiry date of the derogations granted to ScottishPower and Manweb for these requirements to be met. A further derogation, which will lapse only in certain limited circumstances, allows the two distribution businesses of ScottishPower and Manweb to be managed and operated jointly.

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 Act. Licence conditions may be modified, either in accordance with the terms of the relevant licences or in accordance with the procedures laid down in the Electricity Act.

Under the Electricity Act, as amended by the Utilities Act, the Authority may modify a licence condition with the agreement of the licence holders after due notice, public consultation, and consideration of any representations or objections. In the absence of agreement, 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 and report on whether matters specified in the reference relating to the generation, transmission or supply of electricity 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. In determining whether any particular matter operates, or may be expected to operate, against the public interest, the Competition Commission is to have regard to the matters in relation to which duties are imposed on the Secretary of State and the Authority.

If there is an adverse finding, the Competition Commission's report will state whether any adverse effects on the public interest could be remedied or prevented by modification of the licence conditions. 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 objections. The Secretary of State has the power to veto any modification reference.

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 involved ScottishPower giving assurances to the Secretary of State to modify Manweb's PES Licence and ScottishPower's Composite Licence (and Southern Water Services' Water Appointment). ScottishPower's merger with PacifiCorp in 1999 also involved ScottishPower giving undertakings to the Secretary of State to agree to modifications to its Composite Licence.

Term and Revocation of Licences – ScottishPower's Composite Licence and Manweb's PES Licence continue until terminated by not less than 25 years' notice given by the Secretary of State. ScottishPower's and Manweb's second-tier licences for England & Wales continue until terminated by not less than 25 years' notice given by the Secretary of State on or after 19 November 2000 and 1 April 2001 respectively. ScottishPower's and Manweb's second-tier licences for Scotland continue until terminated by not less than 25 years' notice given by the Secretary of State on or after 30 March 2000 and 1 July 2004 respectively. Licences under the Electricity Act, as amended by the Utilities Act, may be revoked in certain circumstances specified in the licences, such as the insolvency of the licensee or the licensee's failure to comply with an enforcement order made by the Authority. In addition, the Secretary of State may revoke each of ScottishPower's generation, transmission and PES licences if ScottishPower ceases to carry on the activities authorised by the respective licence.

Principal Conditions of ScottishPower's Composite Licence and Manweb's PES Licence – ScottishPower's Composite Licence and Manweb's PES Licence require ScottishPower and Manweb respectively to prepare and publish separate accounts for each of ScottishPower's generation, transmission, distribution and supply businesses (first and second-tier and wholesaling business) and Manweb's distribution business. It is a further licence requirement that none of ScottishPower's nor of Manweb's businesses gives any cross-subsidy to, or receives any cross-subsidy from, any of ScottishPower's or Manweb's other businesses, whether regulated by the Composite Licence or not.

A number of Composite Licence, PED and PES licence conditions require ScottishPower and Manweb, respectively, to be party to certain agreements or codes which affect their operational activities: for example, the Grid Code, which includes provisions governing the technical aspects of connections to, and the operation of, the transmission systems. Each PED licensee must also draw up, implement and comply with a Distribution Code, which interacts with the Grid Code and specifies technical requirements for connection to, and the operation and use of, its distribution system; and Codes of Practice on customer relations, which require the approval of the Authority. There are also Electricity Supply Regulations and certain performance standards determined by the Authority which must be complied with.

The modifications made upon the acquisition of Manweb were designed to address the fact that, as a result of the acquisition, Manweb became a subsidiary of ScottishPower. Broadly, the modifications were designed to ring-fence Manweb's regulated businesses (distribution, supply and second-tier supply) from its non-regulated businesses and from ScottishPower's other businesses; to impose certain information reporting requirements on Manweb and ScottishPower to assist the DGES to carry out regulatory functions; and to address the fact that ScottishPower and Manweb are both electricity companies.

As a condition for regulatory clearance of ScottishPower's acquisition of Southern Water, ScottishPower gave assurances to the Secretary of State that it would not operate any new business which is not regulated under the Electricity Act and whose annual turnover accounts for more than 5% of ScottishPower's aggregate annual turnover excluding all subsidiaries, other than as a subsidiary company; ensure that ScottishPower had sufficient management and financial resources to fulfil its obligations to enable the introduction of competition in supply for all customers in its home area; and agree to appropriate modifications to Southern Water's licence.

The undertakings given to the Secretary of State by ScottishPower as a condition for regulatory clearance for its merger with PacifiCorp were aimed principally at ensuring that ScottishPower's UK businesses would not be impacted financially by the merger. The principal undertakings were therefore that the holding company established as a result of the merger would restructure its business in Great Britain as soon as is reasonably practicable, and in any event before April 2002, so as to place generation and any non-electricity activities in separate group companies from the remaining electricity activities; that following restructuring a financial ring-fence would be placed around the PES and transmission businesses of ScottishPower, on similar terms to the standard ring-fence developed by the DGES; and that ScottishPower would ensure that the DGES would continue to have access to the information needed to carry out the duties of the office.

Price Controls
The primary objective of the regulation of the UK 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, such as in the transmission and distribution of electricity, and that in other areas it will take time to develop, as in the supply of electricity. In these areas, regulatory controls are deemed necessary to protect customers in a monopoly market (by determining inflation-limited price caps) and to encourage efficiency.

ScottishPower and Manweb's 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. Since 1995, regulation has tended to restrict price increases to customers to levels below the increase in the retail price index ("RPI"), through a formula expressed as RPI – X. The rationale behind the use of the RPI – X formula is that companies are motivated, during the period of the price control, to maximise efficiencies, knowing that they can retain any element of overperformance for their shareholders. 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.

Since the controls are forward looking (i.e are based on forecasts), and are designed to achieve an allowed rate of return (equal to the cost of capital) for the business, correction factors are also required to adjust tariffs in subsequent years to allow for any over or under recovery of revenues and ensure that the allowed revenue is achieved over the period of the control. The Authority from time to time reviews the price cap formulae applicable to the transmission, distribution and supply businesses. ScottishPower and Manweb participate in reviews of price caps applicable to them by submitting to Ofgem their view of what reasonable efficiency gains and future investment requirements should be built into the determination of the revised price control.

As with any modification to licence conditions, the Authority must undertake a consultation exercise, inviting comments from PES licensees and third parties, before modifying licences to incorporate new price controls. As described above under " The Licensing Regime– Modification of Licences ", licence conditions may be modified, either with the consent of the licensee or, in the absence of consent, following a modification reference to the Competition Commission. The Competition Commission is an independent body whose statutory duty is to determine whether the matters specified in a reference to it operate, or may be expected to operate, against the public interest; and, if so, whether the adverse public interest effect of those factors could be remedied or prevented by modification of the conditions of the licence. 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.

ScottishPower Transmission Price Control and British Electricity Trading and Transmission Arrangements
In December 1999, the DGES announced a revised transmission price control for ScottishPower, to take effect from 1 April 2000 and to run for five years. The DGES also instituted BETTA, which envisages a Great Britain wholesale market for electricity and revised arrangements in respect of the interconnector between Scotland and England & Wales. 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. The new arrangements are currently the subject of continuing consultation and are expected to result in changes becoming effective during 2002-03.

Distribution Price Control
The maximum distribution revenue is calculated from a formula that is based on customer numbers as well as units distributed. In December 1999, the DGES announced revised distribution price controls for ScottishPower and Manweb, to take effect from 1 April 2000 and to run for five years. During the period of the revised distribution price control, the Authority will be carrying out a project aimed at ensuring that revenues and outputs of the business are more closely matched and meet customers' expectations. This will require an examination of the appropriate information and incentives, and is expected to lead to a refinement of the price controls to place less emphasis on periodic reviews and more emphasis on continuous performance comparisons between companies. From April 2002, following completion of the project, it is anticipated that companies' revenues could be adjusted by up to 2% to reflect better or worse than average performance.

Supply Price Control
All customers are now subject to competitive supply, although certain smaller customers remain protected by supply price controls, effective from 1 April 2000 and running for two years. These controls operate as maximum restraints on tariffs and are confined to the two major tariffs for residential customers. All non-residential customers have now been removed from the constraints. The revised price restraints from April 2000 were designed by the DGES to complement, rather than seek to replace, the development of the competitive market. They are designed to leave scope for competing suppliers to offer prices below the levels implied by the constraints and to encourage the retention and new entry of competing suppliers.

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Business Review

Structure of the Gas Industry in the UK

The UK gas industry, which was privatised in 1986, has the following major components:

Beach Terminals
Gas is transported from offshore fields on the UK Continental Shelf to one of seven beach terminals where it is processed before being fed into the onshore transportation system.

The Onshore Transportation System
The onshore transportation system, most of which is owned and operated by Transco, the transportation arm of Lattice plc, and the rest by other public gas transporters, conveys gas from the beach terminals to consumers. The system consists of a high pressure National Transmission System and 13 lower pressure Local Distribution Zones, and is interconnected with the gas transportation systems of continental Europe, Northern Ireland and the Republic of Ireland.

Gas Storage Facilities
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.

Gas Shippers
Gas shippers contract with public gas transporters to have gas transported between the beach terminal and the point of supply. Gas shippers can also access storage facilities.

Supply
Suppliers purchase gas to deliver to their customers by contracting with producers. Suppliers who do not also hold a shipper's licence pay gas shippers to have the gas transported from the beach terminal through a public gas transporter's system

to the customer. Larger industrial and commercial customers, with annual demands exceeding 2,500 therms, have been able to choose their gas supplier for a number of years and competition is well developed in this market. The residential market was opened to competition progressively commencing in April 1996 and completed in May 1998.

In each of Scotland, England and Wales, the gas industry is regulated under the Gas Act 1995 and the Utilities Act by the Secretary of State and by the Authority.

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Regulation of the Gas Industry in the UK

The three main Acts relating to the regulation of the gas industry in England, Wales and Scotland are the Gas Act 1986, the Gas Act 1995 and the Utilities Act. The Gas Act 1986 provided for the privatisation of the industry and for the establishment of the post-privatisation structure. It established the industry's regulatory regime, with the Director General of Gas Supply ("DGGS") as its head. The 1995 Act amended the 1986 Act and introduced the framework necessary for the introduction of residential competition. The Utilities Act transferred the functions of the DGGS to the Authority and provided for the appointment of a Chairman and other members of the Authority by the Secretary of State. The Chairman of the Authority holds office for renewable periods of five years and is the Managing Director of Ofgem.

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 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 in the conveyance or supply of gas under the Fair Trading Act 1973 and certain functions relating to anti-competitive conduct under the Competition Act 1980 and the Competition Act 1998.

The Licensing Regime
The Authority is responsible for granting new licences or licence extensions. The 1995 Act allows for the licensing of three separate activities – public gas transporter, shipper and supplier. ScottishPower is licensed to carry out each of these activities. The Authority also has powers to modify licence conditions, on a similar basis to the regime for electricity.

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Business Review

Structure of the Water Industry in England & Wales

Prior to privatisation of the water industry, the provision of water supply and wastewater services in England & Wales was split between 29 statutory water companies, each incorporated by separate Acts of Parliament which could only supply water, and 10 water authorities established under the Water Act 1973, which could provide both water and wastewater services. Pursuant to the Water Act 1989 ("WA 1989"), the functions of each water authority relating to water supply (except in areas where these functions were carried out through statutory water companies) and the provision of wastewater services were transferred on 1 September 1989 to a Water and Sewerage Company ("WaSC"). At privatisation, certain of the water authorities' other functions, including pollution control, water resource management, fisheries, flood protection and alleviation, and land drainage were transferred to the National Rivers Authority ("NRA").

The relevant provisions of the WA 1989 were consolidated with other functional legislative provisions into the Water Industry Act of 1991 ("WIA 1991"). This provides that each company engaged in public water supply or wastewater services must be licensed by the Secretary of State for the Environment or by the Director General of Water Services ("DGWS"), in accordance with a general authorisation given by the Secretary of State for the Environment.

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Regulation of the Water Industry in England & Wales

The Water Industry is principally regulated under the provisions of WIA 1991 and the Water Resources Act 1991 ("WRA 1991"). WIA 1991 consolidates enactments relating to the supply of water and the provision of wastewater services, including the WA 1989 and other enactments. WA 1989 provided for the privatisation process itself and set up the post-privatisation structure and regulation of the industry. The provisions of the Competition Act also apply to WaSCs.

The WA 1989 (now WIA 1991) provided for the appointment by the Secretary of State for the Environment of an industry regulator. The DGWS holds office for renewable periods of five years, and is the head of the Office of Water Services ("OFWAT") and its staff of administrators, economists and accountants. The Environment Agency ("EA"), which superseded the NRA, regulates discharges by water companies into rivers and coastal waters and the abstraction of water from rivers and ground water. The Drinking Water Inspectorate regulates the quality of drinking water in accordance with EU standards.

Under WIA 1991, the DGWS and the Secretary of State for the Environment must exercise or perform their duties in the manner best calculated to ensure that the functions of a water undertaker and of a sewerage undertaker are properly carried out in every area of England & Wales; and ensure that companies holding Appointments are able (in particular, by securing reasonable returns on their capital) to finance the proper carrying out of their functions. These powers and duties are also to be exercised in a manner best calculated to ensure that the interests of the customer in relation to the fixing and the recovery of charges are protected; and, in particular, to ensure that the interests of customers and potential customers in rural areas are so protected; that no undue preference is shown; and that there is no undue discrimination in the fixing of those charges. The DGWS and the Secretary of State for the Environment are also under a duty to ensure that the interests of customers are protected regarding benefits that could be secured for them by applying a share of the proceeds of any disposals of a WaSC's land in future reviews.

The Competition Act introduced into UK law, with effect from 1 March 2000, the EU prohibitions on anti-competitive agreements and the abuse of a dominant position, and applied them fully to utilities.

The DGWS exercises, concurrently with the Director General of Fair Trading, certain functions relating to monopoly situations in the supply of water or the provision of wastewater services under the Fair Trading Act 1973, and certain functions relating to anti-competitive conduct in connection with the supply of water or securing a supply of water or with the provision of, or securing of, wastewater services under the Competition Act 1980 and the Competition Act 1998.

Duties of Water Undertakers
Under WIA 1991, each water undertaker is under a general duty to develop and maintain an efficient and economical system of water supply within its licence area. It must also ensure that all such arrangements have been made for providing supplies of water to premises in its licence area, for making such supplies available to people who demand them, and for maintaining, improving and extending its mains and other pipes, as are necessary to enable it to meets its water supply obligations under the Act.

Duties of Sewerage Undertakers
Under WIA 1991, each sewerage undertaker is under a general duty to provide, improve and extend such a system of public sewers and to cleanse and maintain these sewers to ensure that its sewerage region is effectively drained. Sewerage undertakers are required to make provision for the emptying of sewers and whatever further arrangements are necessary from time to time for effectively dealing with the contents of sewers. In addition, discharges from wastewater treatment works must be consented to by the EA and sewerage undertakers are responsible under WIA 1991 for regulating discharges of industrial effluent into sewers. Contamination of controlled waters by non-complying effluent being discharged by a treatment works may involve the sewerage undertaker in liability, including clean-up costs.

The Licensing Regime
Following privatisation of the water industry in England & Wales, each of the water and sewerage undertakers, while maintaining its effective monopoly supply, became regulated through an instrument of Appointment. The Appointment confirms the appointment of the water or sewerage undertaker as supplier in its own area and provides for the monitoring of its performance by the DGWS and the Secretary of State for the Environment.

Modification of Licences – Conditions of the Appointment may be modified, either in accordance with the terms of the relevant licences or in accordance with the procedures laid down in WIA 1991. Subject to a power of veto by the Secretary of State, the DGWS may modify the conditions in the Appointment with the consent of the licensee. Before making the modifications, the DGWS must publish the proposed modifications as part of a consultation process, giving third parties the opportunity to make representations and objections which the DGWS must consider. In the absence of consent, the only means by which the DGWS 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 and report on whether matters specified in the reference relating to the carrying out of any function of a company by virtue of its Appointment 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 Appointment. In determining whether any particular matter operates, or may be expected to operate, against the public interest, the Competition Commission is to have regard to the matters in relation to which duties are imposed on the Secretary of State and the DGWS.

If there is an adverse finding, the Competition Commission's report will state whether any adverse effects on the public interest could be remedied or prevented by modification of the licence conditions. If the Competition Commission so concludes, the DGWS must then make such modifications to the Appointment as appear to him 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 objections. The Secretary of State has the power to veto any modification by agreement.

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. Southern Water Services' Appointment was modified as a result of assurances given by ScottishPower as a condition to receiving regulatory clearance for its acquisition of Southern Water plc in 1996.

Term and Revocation of Licences – Southern Water Services' Appointment continues until terminated by not less than 10 years' notice given to Southern Water Services by the Secretary of State for the Environment, expiring not earlier than 25 years after 1 September 1989, the transfer date. Appointments may also be revoked or transferred to another company in certain circumstances specified in WIA 1991 or in the Appointments: for example, the appointee failing to comply with an enforcement order made by the Secretary of State for the Environment or the DGWS, or the appointee being unable to pay its debts.

Principal Conditions of Southern Water Services' Appointment – The principal regulatory provisions which apply to the regulated activities of Southern Water Services are set out in WIA 1991 and regulations and orders made under it. Other business activities of Southern Water, such as waste management and other environmental services, engineering services and systems technology services, if undertaken, fall outside the direct scope of regulation under WIA 1991. Southern Water Services is an appointed WaSC and holds an Appointment regulated under WIA 1991 to supply water and sewerage services within its authorised area, which regulates its appointed activities. Southern Water Services' Appointment requires Southern Water Services to prepare and publish separate accounts, including on a current cost accounting basis, showing separately its appointed business from all other businesses and activities. It is a further Appointment requirement that the regulated business neither gives to, nor receives from, any other business or activity of Southern Water Services, any cross-subsidy, whether those businesses are regulated by the Appointment or not.

Southern Water Services' Appointment was modified following assurances given to the Secretary of State by ScottishPower, as a condition to regulatory clearance of its acquisition of Southern Water plc, to address regulatory concerns arising out of the merger, in particular to ensure the management independence of Southern Water Services and strengthen the ring fencing of its finances.

As a result, the Appointment of Southern Water Services contains an obligation that it must at all times conduct the businesses regulated by its Appointment as if such businesses were substantially Southern Water Services' sole business and Southern Water Services were a separate public listed company. In particular, Southern Water Services must ensure that its Board of directors is independent of ScottishPower and includes two non-executive directors of relevant experience and standing. All directors must disclose to Southern Water Services and to the DGWS any conflicts with their duties as Directors of Southern Water Services and have regard exclusively to the interests of Southern Water Services as a water and sewage undertaker, in the event of a potential conflict with the interests of other group companies. The DGWS must be informed of any change in the identity and functions of the directors of Southern Water Services.

In addition, Southern Water Services must not, without the consent of the DGWS make a loan to, or guarantee any liability of, any group company, or make any disposal of any asset of the regulated business. The payment of dividends by Southern Water Services should not impair its ability to finance its regulated business. Similarly, any financial support or transfer of assets from Southern Water Services to a group company must not adversely affect the former's ability to carry out its functions. In March 1998, Southern Water issued a £100 million variable rate bond to help fund capital expenditure. The bond listing provides a form of Stock Exchange listing for the water business, to compensate OFWAT for the loss of comparative information (as a result of the discontinuance of Southern Water's Stock Exchange listing on the acquisition by ScottishPower). The bond listing imposes an obligation on Southern Water Services to comply with financial information requirements incumbent on a quoted plc and to maintain an investment grade rating for all its corporate debt.

As a condition for regulatory clearance of ScottishPower's acquisition of Southern Water, ScottishPower gave assurances to the Secretary of State that it would not operate any new business that is not regulated under the Electricity Act and whose annual turnover accounts for more than 5% of ScottishPower's aggregate annual turnover excluding all subsidiaries, other than as a subsidiary company; ensure that ScottishPower had sufficient management and financial resources to fulfil its obligations to enable the introduction of competition in supply for all customers in its authorised area; and agree to appropriate modifications to Southern Water's licence.

Price Controls
Southern Water Services' business is subject to price controls. In November 1999, the DGWS announced a revised price control for Southern Water Services to take effect from 1 April 2000 and to run for five years. Large industrial users can now choose their own water and sewerage suppliers. From 1 April 2000, all water companies, including Southern Water, have not been able to recoup from other customers any amounts lost by offering lower tariffs to such industrial users. The regulated charging base to which price limits apply no longer includes tariffs to large industrial users. The Competition Act grants the DGWS concurrent powers with the Director General of Fair Trading in relation to "commercial activities connected with the supply of water or securing a supply of water or with the provision or securing of sewerage services". Companies have been requested by OFWAT to prepare draft codes under which they would enable competitors to gain access to their essential facilities. Southern Water has prepared a draft water access code which was submitted in August 2000.

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Business Review

Environmental Regulation

Throughout its operations, ScottishPower will meet, or better, relevant legislative and regulatory environmental requirements and codes of practice. ScottishPower will publish its sixth Corporate Environment Report in July 2001, copies will be available on request from the Company Secretary.

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Business Review

US Environmental Regulation

Federal, state and local authorities regulate many of PacifiCorp's activities pursuant to laws designed to restore, protect 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.

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.

Air Quality
PacifiCorp's fossil fuel electricity generating plants are subject to regulation under federal, state and local requirements. Emission controls, 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 US Environmental Protection Agency ("EPA") has implemented new regulations addressing regional haze. Carbon dioxide emissions are the subject of growing world-wide discussion and action in the context of global warming, but such emissions are not currently regulated. PacifiCorp's coal-burning plants, along with all other major coal-burning plants in the US, participated in an effort to gather additional information about mercury emissions pursuant to a request issued by the EPA. Based in part on this effort, the EPA has indicated that controls to regulate mercury emissions from coal-burning plants will be brought forward by 2003. PacifiCorp has received Title V Air Operating Permits for all of its coal and natural gas-fired power plants. In response to a 1998 citizen group challenge of the operating permits for PacifiCorp's Naughton and Jim Bridger power plants, the EPA ordered the State of Wyoming to reissue those permits with new continuous opacity monitoring requirements in place. The plants are currently working with the state of Wyoming to determine what, if any, new requirements should be imposed. In 1999, the EPA commenced enforcement actions alleging violations of New Source Review requirements by the owners of certain coal-fired generating plants in the eastern and mid-western US. PacifiCorp is not part of that action. However, in December 2000, the EPA notified PacifiCorp that it is investigating similar issues at four PacifiCorp coal plants. PacifiCorp is co-operating with that investigation by gathering and providing requested information to the EPA.

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 California Public Utilities Commission 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-Up
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.

Water Quality
The Federal Clean Water Act and individual state clean water regulations require a permit for the discharge of waste water, 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.

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Business Review

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, when it formulates proposals for development in connection with certain of its activities. The group is required, 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 provides for environmental guidance to be given by the Secretary of State to the energy regulator, Ofgem, which will also be required to formulate an 'Environment Action Plan'. Detailed Regulations are currently being drawn up for implementation later in 2001. The Utilities Act also provides for energy efficiency targets to be set for licensed suppliers to be implemented by an 'Energy Efficiency Commitment'. Detailed Regulations are currently being drawn up. The Utilities Act also provides 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'. It is anticipated that this obligation will rise to 10% of supplies in the UK by 2010. ScottishPower continues to develop its windfarm business and expects to meet the company's target of 10% generation from renewables by 2010.

The Environmental Protection Act 1990 ("EPA 1990") requires that potentially polluting activities such as the operation of combustion processes (which includes power plant) requires 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 leukemia.

Generation Activities
The principal emissions from fossil-fuelled electricity generation are sulphur dioxide ("SO2"), nitrogen oxides ("NOx"), carbon dioxide ("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.

EPA 1990 is the primary UK statute governing the environmental regulation of power stations. It introduced a system of Integrated Pollution Control ("IPC") in April 1991 for large scale industrial processes, including power stations. Under EPA 1990, the authority for enforcing IPC with respect to emissions to atmosphere in England & Wales is the EA and in Scotland is the Scottish Environment Protection Agency ("SEPA"). Control by the EA and SEPA came into force on 1 April 1996 and was established by the Environment Act 1995 ("EA 1995").

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 will bring modifications to the IPC regime into effect, on a staged basis.

The EU has adopted a framework directive on ambient air quality assessment and management, which came fully into force in May 1998 and 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 Large Combustion Plants Directive ("LCPD"). The EU is currently finalising a "Ceilings Directive" which will implement the SO2 and NOx targets recently agreed in the UNECE Gothenburg Protocol. The LCPD is currently under review and will be replaced by a new control framework. Controls on emissions from existing and new plants will be introduced via the new provisions, the Air Framework Directive and, in the future, by the PPC Regulations.

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. This reduction target applies to the EU as a whole, with each individual Member State being allocated its own target which is 12.5% for the UK. HM Government has announced its intention of unilaterally setting itself a goal of 20% reduction in carbon dioxide emissions by 2010. The UK finalised in 2000 a "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 to be charged on industrial and commercial energy usage, and residential energy efficiency measures. The provisions of the Obligations implemented by the Utilities Act will play an important part in the Programme.

Each of ScottishPower's power stations is required to have IPC authorisation issued by the EA or SEPA. Under IPC, each power station has a single authorisation which regulates emissions of certain pollutants and seeks to minimise pollution of the environment. Each IPC authorisation requires 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. Each authorisation also contains an improvement programme.

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 Directive on Integrated Pollution Prevention and Control, being implemented on a staged basis by the PPC Regulations, will require that all emission and pollution control measures be placed onto a "Best Available Techniques" basis to control impact on the environment.

Under the requirements of the LCPD, HM Government has implemented a Sulphur Strategy which gives effect to a national programme, the National Plan, to reduce SO2 and NOx emissions from power stations. ScottishPower and Scottish & Southern have entered into an agreement providing for the sharing of limits in emissions of SO2 and NOx from existing generating stations in Scotland set out in the National Plan to meet the targets of the LCPD. It also provides for the sharing of station-specific limits on emissions of SO2 and NOx imposed by SEPA at the Peterhead, Longannet and Cockenzie generating stations where capacity is shared between ScottishPower and Scottish & Southern.

Reductions of CO2, SO2 and NOx per unit of electricity generated have been achieved as a result of the group's investments in environmental upgrades, such as low NOx burners and gas reburn, to existing power stations. That proportion of the group's output generated from renewable energy and gas-fired generation, has also increased resulting in further reductions in emissions per unit of electricity produced.

The IPC authorisations granted in 1993 in respect of ScottishPower's existing power stations limit the levels of atmospheric emissions of SO2 and NOx from each station. A number of minor variations have taken place and a full four year IPC review has now been completed by SEPA. This review continues the tightening of emission limits, but provides for allowance in the event of the operator opting to fit and operate Flue Gas Desulphurisation ("FGD") plant.

The company is confident that it will be able to continue the environmental improvements required by potential future limits arising from this review without materially constraining operational and commercial flexibility. In particular, gas reburn technology offers greater potential to reduce emissions than other technology in use elsewhere in the UK. Furthermore, planning consent has been gained for FGD at Longannet. Detailed engineering design work is being undertaken and an installation programme devised to ensure that emission limits will be met.

Water
Since 1 April 1996, the EA has been responsible in England & Wales for the control of water pollution and the maintenance and improvement of the quality of controlled waters, including the regulation of discharges to those waters; for conserving, redistributing and augmenting water resources and for securing the proper use of such resources for land drainage and flood defence. In Scotland, SEPA has largely replaced the River Purification Boards to fulfil these responsibilities. The group is also subject to regulations governing drinking water quality, receiving water quality and wastewater discharges.

Within its general water resource management role, the EA has a duty to operate the system under WRA 1991, whereby water undertakers and other abstractors must have a licence authorising each of their abstractions and other impoundments. It also has a duty to enter into water resource management arrangements with water undertakers to secure the proper management and operation of waters, reservoirs and other works vested in the undertakers. The EA may, and shall if so directed, consider the setting of minimum acceptable flows in rivers and make recommendations to the Secretary of State accordingly.

Under WRA 1991 and the Control of Pollution Act 1974, the EA may require persons to take precautions against pollution, may prohibit or restrict certain activities likely to cause pollution in areas designated by the Secretary of State, and may impose a requirement for a consent to discharge matter from a drain or sewer. When reviewing existing consents and issuing new ones, the EA has said that it will seek to set contamination which causes, or is likely to cause, significant harm to the environment or any pollution of conditions at the level required to at least maintain and, where appropriate, improve the quality of the receiving waters.

HM Government's upgrading of minimum levels of wastewater treatment for coastal works has required further improvements to recently completed new works such as Eastbourne, Shoreham, Dover and Folkestone, as well as additional treatment levels for long-term investment projects at Littlehampton and Bognor, Margate and Broadstairs, and the Isle of Wight. Under EPA 1990, the EA is responsible for maintaining registers containing details of applications for discharge consents, consents granted and the results of samples of effluent and receiving waters. The registers are open to public inspection.

The activities of the WaSCs are affected by the requirements of EU directives including the Drinking Water Directive, the Bathing Waters Directive and the Urban Waste Water Treatment Directive. EU directives are binding on HM Government, not on the WaSCs, as to the result to be achieved within a specified period. It is the responsibility of European Member States, including the UK, to bring into force appropriate national environmental legislation, such as the Urban Waste Water Treatment Regulations to implement these EU directives.

New requirements will be binding on the WaSCs only when they are translated into the law of England & Wales. Any expenditure incurred by a WaSC necessitated by new legislation applying to them in their capacity as water or sewerage undertakers, or by any change in consents as a result of any changes to existing EU directives, or adoption of future EU directives, would be eligible for consideration for a specific K adjustment.

WRA 1991 and the Urban Waste Water Treatment Regulations are the main UK statutes governing water abstraction, receiving water quality and wastewater discharges. This legislation implements the Bathing Waters Directive and the Urban Waste Water Treatment Directive and requires improvements in the treatment of wastewater discharges. The Water Supply (Water Quality) Regulations introduce the requirements of the EU Drinking Water Directive into the UK and govern drinking water quality. In 2000-01, Southern Water spent approximately £134 million to comply with the relevant statutes.

Southern Water, like other WaSCs in the UK, must have a licence from the EA authorising each of its abstractions and certain impoundments. For additional obligations of Southern Water affecting the environment, see the sections of this document entitled " Principal Business Activities – Southern Water " and " Regulation of the Water Industry in England & Wales ".

In addition to its other obligations affecting the environment, Southern Water may be required by the EA to take precautions against pollution, may be prohibited or restricted by the EA from certain activities likely to cause pollution in areas designated by the Secretary of State, and may be required by the EA to obtain a consent to discharge matter (other than sewage or trade effluent) from a drain or sewer. Although recent cases have suggested that commercial enterprises may be fined more heavily than in the past for pollution offences or for violating water quality standards, Southern Water does not believe the level of fines levied on it in 2000-01 will have a materially adverse impact on its operations. Further, in the course of its activities, the EA may carry out anti-pollution works and may recover the cost of such works from the person responsible for the pollution: again, Southern Water does not have a materially adverse exposure in this respect.

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. EA 1995 requires the polluter (or if the polluter cannot be found or has legally transferred its responsibilities by disclosure, the owner or occupant) of contaminated land to clean up any controlled waters, so that environmental compliance is consistent with the intended use of the site.

The UK Government has recently finalised the Contaminated Land Regulations to implement the provisions of EA 1995. This requires 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 a source of pollution, a receptor and a pathway are present. Harm may be eliminated by clean-up or by breaking the source-receptor pathway. Clean-up is only required to 'fit for subsequent use' standards. Other proposals which may impose strict liability for environmental damage are also under consideration by the EU and a Directive may be brought forward. ScottishPower is not currently aware of any liability which it may have under EA 1995 or proposed EU directives which will have a materially adverse impact on its operations.

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Business Review

Employment Regulation

Equal Opportunity
US Business PacifiCorp has an equal employment opportunity and harassment policy which reflects its belief that it can best achieve its objectives by effectively using 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, the Equal Opportunities Commission Equality Exchange and the Women's Engineering Society. The latter aims to promote the study and practice of engineering among women. 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 reported to the executive and shared with the trade unions on an annual basis.

Health and Safety
US Business
PacifiCorp has a safety strategy that focuses on the safety of its employees, customers and members of the public through the utilisation of sound safety policies and practices. The commitment of PacifiCorp to strengthen yet further the safety of its operations is evident in the creation of the position of Director of Corporate Safety. PacifiCorp is also fully committed to the health and well-being of its employees. PacifiCorp staff enjoy an excellent benefits package to ensure that they are cared for in all aspects of health care both during employment and, if they so wish, in retirement.

UK Businesses
ScottishPower's safety strategy is based on a system of corporate determination of strategy, policy and auditing standards, with devolved responsibility for implementation and active leadership from the highest levels. The UK businesses continue to manage their operations to the highest health and safety standards, in the interests of staff, customers and members of the public. The group has a well-established occupational health service and lifestyle health care programme, the UK employees therefore benefit from some of the best occupational health facilities in the UK.

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

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Summary of Key Operating Statistics

Table 1 – Summary of PacifiCorp Generating Facilities
	Location	Energy source	Installation dates	Nameplate rating (MW)		Plant net capability (MW)
Hydro-electric Plants:
Swift	Cougar, WA	Lewis River	1958	240.0		263.6
Merwin	Ariel, WA	Lewis River	1932-1958	135.0		144.0
Yale	Amboy, WA	Lewis River	1953	134.0		134.0
Five North Umpqua Plants	Toketee Falls, OR	N. Umpqua River	1949-1956	133.5		138.0
John C. Boyle	Keno, OR	Klamath River	1958	80.0		90.0
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	99.6	*	99.3	*
Subtotal (53 Hydro-electric Plants)				1,078.1		1,136.5
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)				8,279.5		7,832.0
Notes: * Jointly owned plants; amount shown represents PacifiCorp's share only. Hydro-electric project locations are stated by locality and river watershed.

Table 2 – PacifiCorp Recoverable Coal Reserves as at 31 March 2001
Location	Notes	Plant served	Recoverable tons (in millions)
Craig, Colorado	1	Craig	50
Emery County, Utah	2	Huntington and Hunter	73
Rock Springs, Wyoming	3	Jim Bridger	106

Notes:
1	These coal reserves are leased and mined by Trapper Mining, Inc., a Delaware no-stock corporation operated on a co-operative basis, in which PacifiCorp has an ownership interest of approximately 20%.
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 2001 and 2000, the three months ended 31 March 1999, and the year ended 31 December 1998, were as follows:
		2001	%	2000	%	1999	%	1998	%
Gigawatt hours Sold:
	Residential	13,455	18	13,028	16	3,773	18	12,969	9
	Commercial	13,634	18	12,827	16	2,993	14	12,299	9
	Industrial	20,659	27	20,488	25	4,627	22	20,966	15
	Government, Municipal and Other	705	1	663	1	153	1	651	–
	Total Retail Sales	48,453	64	47,006	58	11,546	55	46,885	33
	Wholesale Sales and Market Trading	27,502	36	34,327	42	9,636	45	94,077	67
Total GWh Sold		75,955	100	81,333	100	21,182	100	140,962	100

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SUMMARY OF KEY OPERATING STATISTICS

Table 4 – Total Electricity Units Distributed in Pacific Power Service Area (GWh)
Year	Residential	%	Commercial	%	Industrial	%	Other	%	Total
1996-97	8,003	32.2	6,580	26.5	10,162	40.9	84	0.4	24,829
1997-98	7,885	30.9	6,770	26.6	10,734	42.0	139	0.5	25,528
1998-99	7,994	31.1	6,908	26.9	10,646	41.5	128	0.5	25,676
1999-00	7,612	30.8	6,766	27.4	10,186	41.3	122	0.5	24,686
2000-01	7,768	31.0	7,041	28.0	10,164	40.5	130	0.5	25,103

Table 5 – Total Electricity Units Distributed in Utah Power Service Area (GWh)
Year	Residential	%	Commercial	%	Industrial	%	Other	%	Total
1996-97	4,873	23.7	4,915	24.0	10,142	49.5	574	2.8	20,504
1997-98	4,940	23.6	5,306	25.4	10,082	48.3	556	2.7	20,884
1998-99	4,998	23.8	5,392	25.7	10,056	48.0	517	2.5	20,963
1999-00	5,416	24.2	6,061	27.2	10,302	46.2	541	2.4	22,320
2000-01	5,687	24.4	6,593	28.2	10,495	44.9	575	2.5	23,350

Table 6 – PacifiCorp Distribution and Transmission Systems Key Information 2000-01
	Pacific Power	Utah Power	Total
Franchise area	67,775 sq miles	67,444 sq miles	135,219 sq miles
System maximum demand	4,082 MW	3,974 MW	8,056 MW
Transmission network (miles)
Underground	–	–	–
Overhead	6,822	8,052	14,874
Distribution network (miles)
Underground	4,847	7,082	11,929
Overhead	26,184	17,493	43,677

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Summary of Key Operating Statistics

Table 7 – Sources of ScottishPower Owned Generating Capacity and Output in the UK and the Republic of Ireland as at 31 March 2001
	Notes	Number of generating sets and/or installed capacity MW	Net output MW	Maximum capacity available MW
Coal:
Longannet		4 x 600	2,304
Cockenzie		4 x 300	1,152
	1		3,456	2,880
Methil	2	2 x 30	Nil	Nil
Oil:
Inverkip	3	3 x 676	Nil	Nil
Gas Turbine:
Rye House	4	1 x 715	715	715
Brighton	5	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		16	16	16
Windfarms:
Barnesmore		25 x 0.6	15	15
Hagshaw Hill		26 x 0.6	16	16
P & L Windfarm	6	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	7	24 x 0.4	10	4
Carland Cross	7	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			5,301	4,500

Notes:
1	Scottish & Southern is entitled to a supply of electricity from part of the capacity of ScottishPower's coal-fired generating stations at Longannet and Cockenzie.
2	The installed capacity at Methil is unavailable for generation.
3	The installed capacity at Inverkip is currently on long-term preservation and is unavailable for generation.
4	Operation of Rye House power station was transferred to ScottishPower from Powergen plc following formal completion of the purchase on 8 March 2001.
5	Brighton power station is owned by South Coast Power Ltd, with ScottishPower and American Electric Power (the US parent company of SEEBOARD) each having a 50% ownership interest.
6	The P & L Windfarm is owned by CeltPower Limited, with ScottishPower and Tomen Power Corporation (U.K.) Limited each having a 50% ownership interest.
7	The windfarms at Coal Clough and Carland Cross are owned by a joint venture between Manweb, Western Power Distribution and Renewable Energy Systems, with Manweb having a 45% ownership interest.

Table 8 – Sources of UK Generating Capacity and Output Available to ScottishPower Under Contract as at 31 March 2001
	Notes	Number of generating sets and/or installed capacity MW	Net output MW	Maximum capacity available MW
Nuclear:
Torness	1	2 x 660	1,236	926
Hunterston B	1	2 x 660	1,230	921
Total Nuclear				1,847
Dual Oil and Gas Fired:
Peterhead	2	2 x 660	1,284	642
Gas Turbine:
Peterhead	3	2 x 120	232	116
Conventional Hydro:
Scottish & Southern	4			200
Total			3,982	2,805

Notes
1	The NEA entitles ScottishPower and Scottish & Southern to 74.9% and 25.1%, respectively, of the electricity generated from British Energy's Hunterston B and Torness nuclear generating stations. Except in limited circumstances, the NEA obliges ScottishPower and Scottish & Southern to pay for all the electricity declared by British Energy to be available from such nuclear stations, whether or not they take such electricity.
2	Following the end of the Miller Gas Plateau, ScottishPower is entitled to 50% of the net output capacity of Scottish & Southern's Peterhead station (or such lesser part of that capacity as Scottish & Southern declares to be available to ScottishPower on any day).
3	The gas turbines installed at Peterhead are primarily for use during an outage on one of the main units at the station to enable the consumption of the gas delivered from the Miller gas field. The use of the gas turbines at these times is subject to agreement with Scottish & Southern.
4	The Hydro Agreement entitles ScottishPower to 400 GWh of electricity from Scottish & Southern's conventional hydro generating capacity during each contract year (although this amount may be reduced during periods of unusually low rainfall or unusually low run-off) and requires ScottishPower to pay for that amount of electricity, irrespective of how much electricity it actually takes.

Table 9 – UK Infrastructure – Power Systems Key Information 2000-01
	ScottishPower	Manweb	Total
Franchise area	22,950 km2	12,200 km2	35,150 km2
System maximum demand	4,382 MW	3,028 MW	7,410 MW
Transmission network (km)
Underground	247	–	247
Overhead	3,851	–	3,851
Distribution network (km)
Underground	40,897	24,086	64,983
Overhead	24,456	21,566	46,022

Table 10 – Total Electricity Units Distributed in ScottishPower's Service Area (GWh)
Year	Residential	%	Commercial	%	Industrial	%	Other	%	Total
1996-97	8,194	37.8	5,758	26.6	6,983	32.2	751	3.4	21,686
1997-98	8,048	37.1	5,809	26.8	7,103	32.7	752	3.4	21,712
1998-99	8,345	37.3	6,041	27.0	7,217	32.3	765	3.4	22,368
1999-00	8,385	37.5	5,983	26.7	7,218	32.2	795	3.6	22,381
2000-01	8,505	37.5	6,016	26.5	7,438	32.8	735	3.2	22,694

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Summary of Key Operating Statistics

Table 11 – Total Electricity Units Distributed in Manweb's Service Area (GWh)
Year	Residential	%	Commercial	%	Industrial	%	Other	%	Total
1996-97	4,930	26.8	3,594	19.5	9,476	51.4	417	2.3	18,417
1997-98	4,916	26.5	3,640	19.7	9,536	51.5	430	2.3	18,522
1998-99	5,037	29.1	3,852	22.2	8,018	46.3	417	2.4	17,324
1999-00	5,204	30.3	3,998	23.3	7,549	43.9	430	2.5	17,181
2000-01	5,460	31.6	4,106	23.7	7,310	42.3	410	2.4	17,286

Table 12 – UK Infrastructure – Southern Water Key Information 2000-01
Franchise area	10,450 km2
Water supply services	1 million premises
	2.2 million people
Water supply	585 million litres per day (average)
Water main	13,302 km
Reservoir storage capacity	42,390 million litres
Wastewater treatment works	390
Wastewater treatment services	1.8 million premises
	4.4 million people
Wastewater treated	1,400 million litres per day

Table 13 – UK Infrastructure – Southern Water Storage Reservoirs as at 31 March 2001
Description	Note	Location	Capacity (Ml)	Approximate acreage
Bewl Water		Kent	31,000	1,135
Darwell		Sussex	4,730	1,091
Powdermill		Sussex	1,060	1,132
Weir Wood	1	Sussex	5,600	470
Note: 1 Includes water treatment works

Table 14 – UK Infrastructure – Southern Water Major Water Treatment Works as at 31 March 2001
Description	Location	Output Ml per day	Approximate acreage
Beauport	Sussex	27.0	4
Burham	Kent	58.0	61
Eastling	Kent	31.0	2
Hardham	Sussex	75.0	35
Otterbourne	Hampshire	102.7	352
Testwood	Hampshire	90.0	184
Twyford	Hampshire	23.0	183
Weir Wood	Sussex	21.8	470
Wingham	Kent	28.0	5

Table 15 – UK Infrastructure – Southern Water Major Wastewater Treatment Works as at 31 March 2001
Description	Location	Equivalent population served	Approximate acreage
Ashford	Kent	110,738	90
Aylesford	Kent	133,107	40
Brighton Portobello	Sussex	270,579	9
Broomfield Bank	Kent	133,893	22
Budds Farm	Hampshire	172,343	52
Canterbury	Kent	105,460	22
Chickenhall Eastleigh	Hampshire	100,781	25
Eastbourne	Sussex	123,035	5
Eastney	Hampshire	226,061	5
Ford	Sussex	136,278	13
Millbrook	Hampshire	131,963	17
Motney Hill	Kent	290,921	181
Peel Common	Hampshire	248,731	77
Weatherlees Hill	Kent	100,054	67
Worthing East	Sussex	137,729	15

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Financial Review

David Nish
Finance Director

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

Overview (2000-01)

For the year to 31 March 2001, group turnover grew significantly to £6,349 million, an increase of £2,234 million (54%), with PacifiCorp contributing revenues of £3,122 million, an increase of £2,411 million. Revenues from retail customers in the US increased by 6% for the year, largely as a result of increased prices and higher demand, in part driven by strong economic growth and unusually hot summer weather in the western US. Despite reductions in wholesale sales volumes of 20%, sales revenues more than doubled, reflecting the significant increase in power prices in the region. The reduction in UK turnover of £176 million was principally related to the impact of the regulatory price reviews and intensified competition within the electricity sector. Thus' external turnover increased by £22 million for the year, compared to the equivalent period in 1999-00 after adjusting for the disposal of the mobile telephone business in the prior year.

Cost of sales were 82% higher at £4,407 million, including a full year's trading from PacifiCorp against four months in 1999-00. Costs also increased due to higher US power purchase costs as a result of the Hunter outage, reduced availability of hydro resources and the increase in retail load. Transmission and distribution costs were higher by £171 million year-on-year, including the impact of a full year's PacifiCorp costs of £158 million. Administrative expenses increased by £83 million in the year, including PacifiCorp costs of £48 million and UK costs increased by £35 million, mainly as a result of the growth of Thus.

Operating profit for the year increased from £961 million to £970 million, up £9 million, despite the impact of the Hunter outage and the UK regulatory reviews. PacifiCorp contributed operating profit of £351 million, after the impact of the Hunter outage, compared to £152 million for the four month period post acquisition to 31 March 2000. Performance in the UK businesses was consistent with the trends reported in our interim and third quarter results, with operating profit of £619 million, compared to £810 million in the previous financial year. The reduction was principally due to the impact of the regulatory reviews and our continued investment in Thus.

As announced in May 2000, an exceptional charge of £121 million has been recognised for the costs of implementing the Transition Plan in PacifiCorp. In the year to March 2000, exceptional charges of £55 million included costs and asset write downs incurred in preparing our Telecoms business for flotation, with a further £262 million of costs relating to impairment of assets in the UK energy and water businesses and restructuring of our UK operations. These charges were more than offset by the £787 million gain from the partial disposal of Thus.

Largely as a result of the inclusion of a full year's results for PacifiCorp, the net interest charge increased by £105 million to £333 million in the year. Profit before tax for the year fell by £108 million to £628 million and the ordinary tax charge, excluding deferred tax, represented an effective tax rate of around 14% on profits before goodwill amortisation and exceptional items. Including deferred tax, the reported tax rate before goodwill amortisation and exceptional items for the year was 22.5%, with the impact of deferred tax on the results for the year being £51 million.

Earnings per share, before goodwill amortisation, exceptional items and deferred tax, were 30.65 pence for the year, compared to 41.22 pence in the same period last year. After adjusting for the impact of deferred tax, earnings per share for the year were 27.86 pence compared to a restated earnings per share of 37.97 pence for the previous year.

The fourth 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%. This is in line with our stated dividend aim of 5% nominal growth for each year through to March 2003. Dividend cover was 1.1 times. Free cash flow for the year was £888 million, £182 million higher than the equivalent figure last year. ScottishPower invested £1,096 million in capital projects, £210 million more than in the previous year. Of this total, £309 million related to PacifiCorp, an increase of £215 million compared to the four month period in 1999-00. Expenditure in the UK infrastructure businesses decreased by £6 million. Net debt increased from £4,842 million to £5,285 million as a result of the Rye House power station acquisition and the impact of foreign exchange movements. Gearing (net debt/shareholders' funds) at 31 March 2001 was 90%, marginally higher than the 87% for 1999-00, restated for the impact of Financial Reporting Standard ("FRS") 19 on deferred tax. Interest cover was 3.0 times. Key group financial information is shown in Table 16.
Table 16 – Key Group Financial Information (2000-01 and 1999-00)
	2000-01	1999-00
Operating profit* (£m)	970.2	961.4
Profit before tax* (£m)	628.0	735.6
EPS* before deferred tax (pence)	30.65	41.22
EPS* (pence)	27.86	37.97
Dividends per share (pence)	26.04	24.80
* Before goodwill amortisation and exceptional items.

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Financial Review

Business Reviews (2000-01)

To provide a sharper focus on developing our businesses, the group has restructured into three divisions. The US Division includes PacifiCorp's regulated and unregulated businesses; the UK Division includes Generation and Energy Supply; and the Infrastructure Division, which includes Power Systems and Southern Water in the UK, and which will also seek benefits between our US and UK infrastructure businesses.

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Financial Review

US Division

Turnover in PacifiCorp was £3,122 million in the year, 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, to a full twelve month period for 1999-00, turnover was £845 million higher in the current year, due to higher retail volumes and the impact on wholesale revenues of the high power prices in the western US. Residential revenues increased by £37 million, or 7%. Growth in the average number of customers of 2% added £10 million to revenues, with price increases in Oregon, Utah and Wyoming adding a further £19 million to revenues in 2000-01. Volume increases of 3%, primarily due to weather, increased residential revenues by £8 million. Industrial revenues increased by £24 million, or 5%, primarily from price increases in Oregon, Utah and Wyoming and increased irrigation usage. Commercial revenues increased by £29 million, or 6%, due to strong economic activity in Utah and Oregon. Growth in the average number of commercial customers of 3% added £15 million to revenues, with volume increases of 6% and higher prices adding £14 million to revenues. Other retail revenues increased by £41 million mainly due to an increase in wheeling revenues from increased usage of PacifiCorp's transmission system by third parties. Wholesale revenues increased by £718 million, or 102%. Sales prices for short-term firm and spot market sales averaged $107 per MWh in 2000-01 compared to $27 per MWh in 1999-00, resulting in £1,069 million of additional revenues. Partially offsetting this was a 27% decrease in short-term firm and spot market sales that decreased revenues by £375 million. This decrease in volume was due to the sale of the Centralia plant and mine, the decrease in hydro availability, the outage of the Hunter unit, and the increase in retail load requirements, all of which impacted the amount of available power to sell on the short-term and spot market. Increased prices and volumes relating to long-term firm contracts added £22 million to revenues. Other revenues in the US Division reduced by £4 million during the year.

Operating profit from PacifiCorp for the financial year 2000-01 was £351 million, after the impact of the Hunter outage. Strong economic growth and abnormal temperatures have led to increased retail demand in the western US and retail sales revenues have increased in the year by 6%. This growth, combined with lower than normal hydro generation, meant demand exceeded supply, resulting in exposure to high power prices in the region. Purchased power costs increased year-on-year by over £1 billion (159%) which were largely offset by increased wholesale sales. The key financial information is shown in Table 17.

Table 17 – US Division (2000-01 and 1999-00)
	2000-01	1999-00
External turnover (£m)
– PacifiCorp	3,122.3	711.7
Operating profit* (£m)
– PacifiCorp	351.3	151.7
* Before goodwill amortisation and exceptional items.
Figures for 1999-00 represent the eexternal turnover and operating profit for the four months from date of acquisition to 31 March 2000.

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Financial Review

UK Division

Generation Wholesale
Generation Wholesale turnover increased by £18 million in the year to £276 million, with a higher proportion of sales now to third parties as competition continues to develop. Agency sales grew by £53 million in the year, with volumes increased by 2,042 GWh to 3,874 GWh. Export sales in England & Wales reduced by £41 million, with volumes 1,705 GWh lower at 4,561 GWh. Interconnector utilisation averaged 1,333 MW in the year. The acquisition of Rye House power station in March 2001 increased revenues in the year by £8 million.

Operating profit in Generation Wholesale was £93 million in the year, down £14 million compared with the prior year, due to the continuing effects of competition on wholesale prices. Our new 400 MW combined-cycle gas turbine ("CCGT") plant at Brighton is now operational and produced a contribution to joint venture operating profits of £8 million in the year.

Energy Supply Turnover in Energy Supply was £1,708 million in the year, a reduction of £191 million on 1999-00. Electricity sales in our home area in Scotland were £857 million, representing a reduction of £153 million on the previous year, with volumes reduced by 10% to 16,673 GWh, primarily due to the impact of competition in the residential electricity market and downward pressure on prices. In the Manweb area turnover fell by £84 million to £403 million, both as a result of the impact of competition and from lower prices allowed under the regulatory formulae. Domestic customer retention rates in our home areas remain competitive at 76% in the ScottishPower area and 74% in Manweb. Electricity sales outside our home areas increased by £25 million to £209 million as we continue to grow the residential and small business customer bases outside our home areas. Gas and other energy sales also increased strongly, by £21 million, to £239 million. The business now supplies 3.5 million electricity and gas customers in the UK. Energy Supply contributed operating profit of £36 million for the year. Applying Ofgem's revised cost allocations, this was a £12 million improvement against the equivalent period in 1999-00. Electricity margins in our home areas have improved as the business continues 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 are in part offset by increased costs of capturing and serving our customer base, and increased system depreciation charges. The key financial information is shown in Table 18.
Table 18 – UK Division (2000-01 and 1999-00)
	2000-01	1999-00
External turnover (£m)
– Generation	275.7	257.8
– Energy Supply	1,708.2	1,899.3
Total	1,983.9	2,157.1
Operating profit* (£m)
– Generation	92.9	106.8
– Energy Supply	36.1	50.6
Total	129.0	157.4
* Before goodwill amortisation and exceptional items.

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Financial Review

Infrastructure Division Power Systems In the past, sales from the Power Systems business have been mainly internal to our Energy Supply business. As a result of competition in home markets, Power Systems external sales continue to increase, up by £40 million in the year to £213 million, as distribution and transmission use of system charges are recovered from other electricity suppliers. In Power Systems, operating profit was £324 million for the year. After adjusting for Ofgem's revised cost allocations on a consistent basis year-on-year, this was £64 million lower than in the equivalent period in 1999-00, with reduced prices allowed under the distribution and transmission regulatory reviews in part offset by savings in controllable costs. Southern Water Southern Water's contribution to group turnover decreased by £49 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 in the year were just over 13,000, and 21,000 customers opted to switch to metered supply. Southern Water contributed £221 million to operating profits, £65 million lower than last 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 remains on target to achieve cash savings of £67 million by March 2003. The key financial information is shown in Table 19.
Table 19 – Infrastructure Division (2000-01 and 1999-00)
	2000-01	1999-00
External turnover (£m)
– Power Systems	212.6	172.6
– Southern Water	421.6	470.5
Total	634.2	643.1
Operating profit* (£m)
– Power Systems	324.2	361.2
– Southern Water	221.2	286.5
Total	545.4	647.7
* Before exceptional items.

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Financial Review

   

Other Businesses

Telecoms (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. Thus has achieved its revenue target for the year and continues to deliver quarter-on-quarter improvements in financial performance.

Other Businesses
Turnover in the Other UK businesses totalled £409 million, an increase of £9 million on last year. The Appliance Retailing business turnover was £317 million in the year, £10 million lower than in 1999-00, with like-for-like sales 3% lower.

In the Other UK businesses, operating profits of £3 million were £12 million lower than last year, largely as a result of competitive trading conditions in our Appliance Retailing business. The key financial information is shown in Table 20.

Table 20 – Other Businesses (2000-01 and 1999-00)
	2000-01	1999-00
External turnover (£m)
– Telecoms (Thus)**	199.4	177.1
– Other	409.5	400.3
Total	608.9	577.4
Operating profit/(loss)* (£m)
– Telecoms (Thus)	(58.0)	(9.5)
– Other	2.5	14.1
Total	(55.5)	4.6
* Before goodwill amortisation and exceptional items.
** Adjusted for disposal of mobile telephone business in 1999-00.

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Financial Review

Interest, Tax, Earnings and Dividends (2000-01) Interest and Tax 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. 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. Taxation, excluding deferred tax, in the year was £90 million, representing an effective tax rate of around 14% on profits before goodwill amortisation and exceptional items. The impact of FRS 19 is fully reflected in the 2000-01 Accounts and the deferred tax charge for the year was £51 million. The group's effective tax rate, before goodwill amortisation and exceptional items was 22.5%, including the impact of deferred tax, compared to 28.1% in the previous year. Key interest and tax information is shown in Table 21. 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 last year's Accounts. Excluding the impact of exceptional items, profit after tax decreased by £129 million to £359 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, as restated to include deferred tax. Excluding the impact of deferred tax, earnings per share for the year were 30.65 pence, compared to 41.22 pence in 1999-00, a reduction of 26%. The exceptional charges of £121 million before tax and £75 million after tax are reflected in the Accounts for the year to 31 March 2001, resulting in a decrease in group earnings per share of 4.09 pence. 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 from April 2000. Group dividend cover, excluding exceptional items and goodwill amortisation, fell to 1.1 times from 1.5 times the previous year, restated for the impact of deferred tax.
Table 21 – Interest and Tax (2000-01 and 1999-00)
	2000-01	1999-00
Interest charge* (£m)	332.9	227.5
Tax charge* excluding deferred tax (£m)	90.1	161.7
Tax charge* including deferred tax (£m)	141.1	206.9
* Before exceptional items.

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Financial Review

Capital Expenditure and Cash Flow (2000-01)

Capital Expenditure
The group continued to invest in its businesses with net capital expenditure for 2000-01 of £1,096 million, an increase of £210 million over 1999-00, which included four months' expenditure in PacifiCorp.

US Division
PacifiCorp capital expenditure amounted to £309 million. Expenditure of £169 million was focused on improving the quality and reliability of the electricity supply to customers, and on expanding the network to meet demand for new electricity supply. Transmission investment was made to reinforce and refurbish specific parts of the overhead line system and on network expansion to support new business opportunities. Spend on generation projects was £117 million. To ease the undercapacity in the region and to take advantage of market opportunities, projects are currently underway to construct, or contract output from, 940 MW of new generation, an increase of over 10% to existing capacity, from both regulated and unregulated sources. These new sources of power will include state-of-the-art gas-fired generation, additions to existing facilities, and output from the world's single largest windfarm.

 

UK Division Capital expenditure in our UK Division totalled £158 million in the year, an increase of £85 million. Generation Wholesale expenditure of £121 million was £89 million higher than in 1999-00, including £35 million of spend on the Public Finance Initiative project at Daldowie and a further £19 million on the development of windfarms. Expenditure on new Combined Heat and Power plants totalled £33 million in the year. In Energy Supply, expenditure of £37 million primarily related to the development of billing systems and customer solutions. Infrastructure Division In Power Systems, net capital expenditure for the year amounted to £152 million, a decrease of £23 million on 1999-00 as the business continues to focus on delivering the regulatory contract. The business spent £125 million on Distribution projects, including £41 million to improve the quality and reliability of the electricity supply to customers, and £45 million on expanding the network to meet demand for new electricity supply. A further £29 million was invested in Transmission projects to reinforce and refurbish specific parts of the overhead line system and on network expansion to support new business opportunities. In Southern Water, the current year marks the beginning of the five year regulatory period and capital expenditure amounted to £308 million, £45 million lower than 1999-00. This included £204 million on wastewater treatment and disposal as the investment programme focused on the achievement of the main regulatory outputs agreed with OFWAT. The composition of the programme was dominated by construction of new wastewater treatment facilities as required by European Union Directives. Construction of major wastewater treatment schemes was completed at Newhaven, Hythe and Littlehampton & Bognor with further significant works progressing at Portsmouth & Havant, Swalecliffe, Hastings, Dover & Folkestone, Worthing, Shoreham and Seaclean Wight. A further £43 million was spent on water distribution and treatment, with the principal focus on ongoing mains renovation work, continuing leakage control and a significant asset maintenance scheme at Hardham. Other Businesses Thus' expenditure in the year was £159 million, including £67 million on network development and £53 million on core telecoms products. Expenditure in the Internet services business was £12 million and a further £15 million was incurred in the year on information systems. Capital expenditure in the Appliance Retailing business was £10 million. Cash Flow Net cash inflow from operations increased from £1,118 million to £1,412 million, due to the inclusion of a full year's trading from PacifiCorp. Net interest paid of £363 million was £107 million higher than 1999-00, as a result of the impact of PacifiCorp on net debt, whilst there was a decrease in tax paid of £2 million. Free cash flow for the group of £888 million was £182 million higher than the equivalent figure in the prior year. From this was funded capital expenditure of £1,144 million, an increase of £226 million as a result of a full year's spend in PacifiCorp and higher expenditure in our UK Generation business to develop our plant portfolio. Net cash inflows from acquisitions and disposals of £483 million primarily relate to the sale of the group's Australian assets and the Centralia plant and mine, in part offset by the costs of acquiring Rye House power station in March 2001. Dividends paid to shareholders amounted to £471 million, up from £406 million last year due to the 5% increase in dividends per share and the enlarged shareholder base following the PacifiCorp acquisition. Net debt at 31 March 2001 was £5,285 million, an increase of £444 million compared with a year ago, principally due to the acquisition of Rye House and the impact of foreign exchange movements. Gearing (net debt/shareholders' funds) at 31 March 2001 was 90%, marginally higher than 87% at 31 March 2000, as restated for the impact of FRS 19 on deferred tax. Key capital expenditure and cash flow information is shown in Table 22.
Table 22 – Capital Expenditure and Cash Flow (2000-01 and 1999-00)
	2000-01	1999-00
Net capital expenditure (£m)	1,095.6	887.0
Free cash flow (£m)	887.6	705.3
Net debt (£m)	5,285.1	4,841.5

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Financial Review

Overview (1999-00)

The financial results for the year to 31 March 2000 reflect, for the first time, the consolidation of four months' trading from our US subsidiary PacifiCorp, following the acquisition in November 1999.

Group turnover grew during the year by £873 million to £4,115 million, an increase of 27%. Four months' trading from PacifiCorp's US operations contributed £712 million to external turnover, £27 million lower than the equivalent four month period in 1998-99. Wholesale revenues were £48 million lower due to the revised energy trading strategy adopted in 1998. This was partially offset by other sales increases of £21 million, primarily as a result of customer growth. Turnover in the UK Division decreased in the year by £15 million (0.7%) to £2,157 million. Continued growth in new gas and out of area electricity customers increased turnover by £111 million; the impact of competition in our home area resulted in increased Generation revenues from other electricity suppliers; and we experienced growth in sales of wholesale electricity. This was offset by a reduction of £165 million in our home electricity supply markets as competition developed. In our Infrastructure Division, turnover increased by £102 million due to price increases allowed under the regulatory formulae. Total Telecoms sales, including mobile telephone operations which were disposed of in November 1999, increased by £23 million in the year to £243 million; of which turnover for Thus increased by 31% to £217 million. The Appliance Retailing business continued to expand and increased its turnover by £40 million.

In line with turnover growth, cost of sales were 30% higher at £2,425 million, largely as a result of the inclusion of PacifiCorp. Transmission and distribution costs increased by £93 million year-on-year, including PacifiCorp costs of £91 million. Administrative expenses increased by £71 million in the year, including PacifiCorp costs of £55 million and UK costs increased by £16 million, largely as a result of higher depreciation charges. The UK infrastructure businesses have further reduced costs during the year and continue to use benchmarking as a tool to substantially reduce underlying operating costs and improve performance. The UK customer facing businesses continue to invest in brand development, marketing and service, to grow energy and telecommunications revenues. The PacifiCorp acquisition, together with continued strong control over operating costs, led to a significant increase in operating profit to £961 million, up £157 million. Performance in the UK businesses was consistent with the modest growth trends reported in our interim results, with operating profit increased to £809 million, compared to £804 million in the previous financial year. PacifiCorp contributed operating profit of £152 million. The net interest charge for the UK businesses increased by £16 million to £177 million, excluding £16 million of exceptional charges incurred on restructuring the debt portfolio. This increase reflects the rising trend of interest rates, the continuing capital investment in UK infrastructure businesses and the impact of the share buy-back programme. Proceeds from the partial flotation of Thus partly offset these increases. Including PacifiCorp and the exceptional debt restructuring costs, group interest increased by £82 million to £243 million in the year. During November 1999, 49.9% of Thus was floated on the London Stock Exchange giving rise to an exceptional gain before tax of £787 million. Exceptional charges of £55 million have been recognised in respect of withdrawal from the use of fixed radio access technology in our Telecoms business and from the loss on disposal of our mobile telephone joint venture. In addition, exceptional charges of £262 million before tax have been recognised during the second half of the year, including the costs of restructuring our UK operations, and provisions for the impairment of fixed assets following the outcome of the regulatory reviews, and provisions for irrecoverable costs from energy contracts. Profit before tax, including exceptional items and goodwill amortisation, increased sharply in the year, by £505 million to £1,149 million. The underlying profit before tax grew by £91 million to £736 million. The tax charge represented an effective tax rate of 28.1%, compared to 27.1% in the previous year. Earnings per share after exceptional items and goodwill amortisation, increased by 61% in the year to 63.69 pence; underlying earnings per share were 37.97 pence, a reduction of 4% on the equivalent figure last year, due to the relative seasonality of profits earned by PacifiCorp in the period since acquisition. The final quarter dividend of 6.20 pence per share brought the total dividends per share for the year to 24.80 pence, an increase of 10.2%. This is in line with our dividend aim for the period to March 2000. Group dividend cover fell to 1.5 times from 1.8 times in the previous year. Free cash flow for the year was £705 million, £3 million higher than the equivalent figure last year. The group invested £886 million in capital projects during the year, £132 million more than in the previous year, with £94 million relating to PacifiCorp. Expenditure in the UK infrastructure businesses reduced by £35 million and investment in Energy Supply and Thus increased by £73 million. Net debt increased from £2,421 million to £4,842 million as a result of the PacifiCorp acquisition, offset in part by the proceeds from the partial flotation of Thus. Gearing (net debt/shareholders' funds) at 31 March 2000 fell to 87% compared to 201% a year ago. Interest cover remained prudent at 4.2 times. Key group financial information is shown in Table 23.
Table 23 – Key Group Financial Information (1999-00 and 1998-99)
	1999-00	1998-99
Operating profit* (£m)	961.4	804.0
Profit before tax* (£m)	735.6	645.0
EPS* before deferred tax (pence)	41.22	42.52
EPS* (pence)	37.97	39.70
Dividends per share (pence)	24.80	22.50
* Before goodwill amortisation and exceptional items.

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Financial Review

Business Reviews (1999-00)

US Division

PacifiCorp's results have been consolidated for four months' trading from date of acquisition.

Turnover for PacifiCorp's retail and wholesale activities totalled £692 million, £14 million lower than in the previous year. Sales to residential customers for the four month period were £197 million, an increase of £4 million as a result of customer growth of 1.5%. Sales to commercial customers increased by £9 million, again as a result of customer growth, with customer numbers increasing by 3%. Industrial sector sales increased by 278 GWh and £9 million as a result of the pilot programme to test competitive markets taking place in the previous financial year and improved economic conditions. Wholesale sales of electricity were £48 million lower at £192 million as the revised energy trading strategy adopted in 1998 took effect.

Operating profit from PacifiCorp for the period was £152 million, in line with expectations and £9 million higher than the four month period in the previous year, primarily as a result of lower power purchase costs in the Retail and Wholesale businesses. The group profit and loss account for the year to 31 March 2000 excludes any results of businesses held for disposal, principally Powercor, PacifiCorp's Australian subsidiary. The key financial information is shown in Table 24.
Table 24 – US Division (1999-00 and 1998-99)
	1999-00	1998-99
External turnover (£m)
– PacifiCorp	711.7	738.9
Operating profit* (£m)
– PacifiCorp	151.7	142.9
* Before goodwill amortisation.
Figures for 1999-00 represent the external turnover and operating profit for the four months from date of acquisition to 31 March 2000.
Figures for 1998-99 represent the external turnover and operating profit for the four months to 31 March 1999 and have been included for comparative purposes only.

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Financial Review

UK Division Generation Wholesale Generation Wholesale turnover increased sharply in the year, up 18% to £258 million, with growth in volumes through higher exports, up by 217 GWh to 6,266 GWh and increased agency sales as a result of competition in the Scottish market, offset in part by lower Pool prices. Operating profit in Generation Wholesale was £107 million in the year, down £8 million compared with the prior year, due to the effects of competition. Margin reductions have been offset by lower operating costs, with increased operating efficiency and lower administration costs. Energy Supply Electricity sales in our home area in Scotland were £1,010 million, representing a reduction of £106 million on the previous year. Volumes in the ScottishPower home area reduced by 6.9% to 18,461 GWh, primarily due to the impact of competition in the residential electricity market and downward pressure on prices in the industrial and commercial sectors. In the Manweb area turnover fell by £59 million to £487 million, both as a result of the impact of competition and from lower prices allowed under the regulatory formulae. Sales outside our home area in England & Wales increased by £46 million to £184 million as we continue to grow the residential and small business customer bases. Gas and other energy sales also increased significantly, by £65 million, to £218 million. In Energy Supply, electricity profit in Scotland, as expected, reduced by £10 million to £26 million, with lower generation costs more than offset by price reductions, loss of customers due to competition and increased systems depreciation. Operating profit from sales in England & Wales outside our home areas was £1 million, an improvement from last year's break-even position, despite absorbing £5 million of additional capture costs for new electricity customers won in this market. In the commercial and residential gas markets the operating loss, at £6 million, was £10 million better than in the prior year, after charging continuing customer capture costs of approximately £15 million and increased costs from serving the expanded customer base, offset by margin obtained from supplying new gas customers. Payback on our initial investment in acquiring a new residential gas customer continues to be favourable. Operating profits for Manweb's Energy Supply business reduced by £7 million to £30 million, due to a reduction in tariffs and a loss of customers through competition. Overall, due to the continued investment for growth, Energy Supply profits reduced by £6 million to £51 million. The key financial information is shown in Table 25.
Table 25 – UK Division (1999-00 and 1998-99)
	1999-00	1998-99
External turnover (£m)
– Generation	257.8	219.0
– Energy Supply	1,899.3	1,953.4
Total	2,157.1	2,172.4
Operating profit* (£m)
– Generation	106.8	115.3
– Energy Supply	50.6	56.7
Total	157.4	172.0
* Before exceptional items.

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Financial Review

Infrastructure Division

Power Systems
Sales from the Power Systems business historically have been largely internal to our Energy Supply business. As a result of competition in home markets, Power Systems external sales increased by £71 million to £173 million, as distribution and transmission use of system charges are recovered from other electricity suppliers.

In Power Systems, operating profit increased by £10 million to £361 million. Transmission operating profit improved by £13 million to £97 million with price increases allowed under the regulatory formula and ongoing cost savings partially offset by higher rates and depreciation. Distribution operating profits reduced by £3 million, with revenues slightly improved from higher sales volumes in Scotland, and continuing cost savings offset by increased depreciation charges, costs of tree cutting to protect network performance and new industry costs associated with the operation of the competitive electricity market.

Southern Water
Southern Water's contribution to group turnover increased by £31 million to £470 million due to allowed price increases under the regulatory formula. New customer connections in the year were just over 13,000, whilst some 26,000 Southern Water customers opted to switch to metered supply.

Southern Water contributed an additional £24 million of operating profit, rising to £286 million, from increased revenues and further cost savings delivered by the Way Ahead initiative during the year of £16 million. These savings offset the additional costs of new cost obligations arising from the operation of new wastewater treatment plants and higher depreciation. The key financial information is shown in Table 26.

Table 26 – Infrastructure Division (1999-00 and 1998-99)
	1999-00	1998-99
External turnover (£m)
– Power Systems	172.6	101.4
– Southern Water	470.5	439.5
Total	643.1	540.9
Operating profit* (£m)
– Power Systems	361.2	350.6
– Southern Water	286.5	262.2
Total	647.7	612.8
* Before exceptional items.

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Financial Review

Other Businesses Telecoms (Thus) Total sales in Telecoms increased by £23 million to £243 million, of which £217 million related to Thus. External turnover in Telecoms increased by £22 million to £203 million, of which £177 million related to Thus. The costs of continued investment in its growth strategy resulted in an operating loss of £10 million, compared to an operating profit of £11 million in 1998-99, due to the costs of developing a national network and increased marketing costs associated with growing the customer base. Other Businesses Turnover in the Other UK businesses totalled £400 million, up from £348 million in the previous year. The Appliance Retailing business continued to expand and increased its turnover by £40 million to £327 million, due to increased sales volumes and new store openings, with appliance sales growing by 10% in the year and like-for-like sales increasing by 6%. Operating profit in the Other UK businesses increased by £6 million to £14 million. The key financial information is shown in Table 27.
Table 27 – Other Businesses (1999-00 and 1998-99)
	1999-00	1998-99
External turnover (£m)
– Telecoms (Thus)**	177.1	180.7
– Other	400.3	348.3
Total	577.4	529.0
Operating profit/(loss)* (£m)
– Telecoms (Thus)	(9.5)	11.5
– Other	14.1	7.7
Total	4.6	19.2
* Before goodwill amortisation and exceptional items.
** Adjusted for disposal of mobile telephone business in 1999-00.

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Financial Review

   

Interest, Tax, Earnings and Dividends
(1999-00)

Interest and Tax
The net interest charge of £243 million was £82 million higher than in 1998-99 due to the continued investment in capital expenditure, the impact of the share buyback programme offset by the benefit of the proceeds received from the partial flotation of Thus. This interest charge includes £16 million of exceptional charges arising from changes to the group's debt portfolio. The average interest rate for the UK businesses during the year was 7.9%, versus 8.0% in 1998-99. The inclusion of PacifiCorp increased the interest charge by £50 million, with an average interest rate in the four month period of 7.0%. Interest cover before exceptional items and goodwill amortisation was 4.2 times against 5.0 times in the prior year.

The taxation charge for the year was £263 million, £88 million higher than 1998-99. This amount includes an exceptional tax charge of £56 million, primarily as a result of the gain on the partial flotation of Thus. The effective tax rate was 28.1% compared to 27.1% 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 £886 million, an increase of £417 million. Excluding the impact of exceptional items, profit after tax increased by £19 million (4%) to £488 million. With a weighted average 1,390 million shares in issue during the year, earnings per share were 37.97 pence, a reduction of 4% on the previous year.

Net exceptional gains of £470 million before tax and interest and £398 million after tax and interest are reflected in the Accounts for the year to 31 March 2000, resulting in an improvement to group earnings per share of 28.63 pence.

The final quarter dividend of 6.20 pence per share brought the total dividends per share for the year to 24.80 pence, an increase of 10.2%, consistent with our dividend aim for the period to March 2000. Group dividend cover fell to 1.5 times from 1.8 times the previous year. From April 2000 we aim to grow dividends by 5% per annum for each of the next three financial years.

Treasury
The treasury focus during the year was on further refinancing of the group's debt 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.

Following the PacifiCorp acquisition, the group's external borrowings are sourced in two separate pools of similar size. In the UK, Scottish Power UK plc ("SPUK") continues to be the finance vehicle for the bulk of the UK activities. In the US, most of the debt is issued by PacifiCorp, and is entirely denominated in US dollars. In both cases regulatory constraints apply to financing activities. Scottish Power plc is not permitted to borrow from its subsidiaries and is currently financed by way of dividend. It has no external borrowing facilities at present.

In the UK under SPUK's Euro-Medium Term Note Programme, established in November 1997, several issues were undertaken during the financial year. These included a $100 million, two-year floating rate issue in April 2000, three index-linked issues amounting to £175 million to October 2024 at 3.494% issued between October 2000 and February 2001 and a £200 million, 20-year, 5.90% issue in February 2001. In addition to these, there were six other smaller issues with maturities of five years.

Cumulative issues outstanding under the programme now total $3,066 million against a programme limit of $4,000 million. SPUK will continue to issue bonds under the programme which allows the UK part of the group continued access to a variety of funding sources and the ability to tap market demand as and when appropriate. As part of the group's strategy to develop new funding sources, a £50 million 10 year loan from the European Investment Bank ("EIB") was borrowed for Manweb plc in February 2001. Total borrowings from the EIB now amount to £343 million. During the year SPUK has taken on index-linked liabilities of £275 million, both through issues of debt and through swapping fixed rate debt into index-linked. This represents around 10% of the UK debt portfolio in recognition of the fact that a large percentage of UK revenues are linked to inflation.

The refinancing activity has reduced short-term debt and permitted a reduction in bank facilities. In September 2000 notice was given to reduce SPUK's revolving credit facility to £1,000 million. This facility matures in June 2001 and negotiations are underway to replace it with a new £1,000 million facility. The facility acts principally as committed support for issues of commercial paper.

In the US, the disposals of Powercor and Hazelwood have resulted in a reduction in net debt. A proportion of the proceeds from the sale was used to repay junior subordinated debentures. A further amount has been lent by PacifiCorp Group Holdings to SPUK.

The group continues to manage its interest rate exposure by maintaining the majority 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 non-functional 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's continuing policy is to maintain at least 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 has entered into borrowing agreements for periods out to 2039. In addition, SPUK has 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 2001, the interest rate on some 71% (UK 70%, US 72%) of debt was fixed and the interest rate on a further 3% of total borrowings was capped (all UK).

The weighted average period of maturity of year-end fixed debt and swaps was 11 years (UK 10 years, US 13 years), while the forward cover on capped debt was for an average period of just over a year (all UK). Accordingly, changes in floating interest rates will have a limited impact on interest payable by the group.

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 are now A1, A and A+ from the three agencies respectively. PacifiCorp's senior secured debt is rated A2, A+, A and its unsecured debt is rated A3, A–, A–. Short-term ratings of P–1, A–1 and F–1 apply to both companies. PacifiCorp Group Holdings has slightly lower ratings although they remain investment grade. On 22 January 2001, Moody's changed their ratings outlook on PacifiCorp securities to negative from stable, citing increasing concerns about ongoing high costs of wholesale power in the Pacific Northwest. On 13 February 2001, Standard & Poor's placed the ratings of the entire ScottishPower group on credit watch. This will remain the case until the wholesale power situation has been resolved.

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Financial Review

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 summarise the financial instruments, derivative instruments and derivative commodity instruments held by the group at 31 March 2001, 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. The instruments held by the group are not leveraged and are not held for financial trading purposes.

Financial Instruments and Risk Management
Overview
The main financial risks faced by the group are interest rate risk, foreign exchange rate risk, liquidity risk and energy price 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 ("FRAs"), forward contracts, futures and contracts for differences ("CfDs"). The group treasury, which is authorised to conduct the day-to-day treasury activities of the group, reports annually to the Board and is subject to both internal and external audit.

In the UK, the Energy Trading Centre which is authorised to carry out activities to manage electricity and gas price risk, reports monthly to a risk committee which includes three executive directors. 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. This trading activity is reviewed as part of regular risk management meetings including ScottishPower and PacifiCorp directors and external consultants.

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 using a spectrum of financial instruments to maintain a majority of the group's debt portfolio at fixed rates. This involves either issuing fixed rate debt or swapping floating rate debt obligations into fixed rates by either interest rate swaps or a string of FRAs. 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 overall policy framework with regard to the fixed/ floating debt mix has been approved by the Board. At 31 March 2001, 71% (2000 78%) of the group's debt was either issued as fixed or converted to fixed rates using interest rates swaps. £100 million of FRAs were outstanding as at 31 March 2001 (2000 £nil).

All 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 any 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 exposed to any material concentration of credit risk.

Foreign exchange risk management
Following the PacifiCorp acquisition the significance of foreign currency risk has risen. Cross border trade-related cash flows remain limited to the impact of capital equipment and fuel and are not significant in terms of the overall size of the group. The dividend stream which flows from PacifiCorp to the holding company amounts to over $300 million annually and can be sold forward on a graduated basis for periods up to three years in order to minimise the effect of fluctuations in the £/$ exchange rate. The group's US net assets are not currently matched by borrowing in US dollars and all SPUK's debt is either denominated in sterling or, if originally denominated in currencies other than sterling, is swapped to sterling. The group uses forward contracts to partially hedge its US net assets.

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 has undrawn committed revolving credit facilities totalling £1,352 million, as at 31 March 2001, which provide backstop liquidity should the need arise.

Energy Price Risk Management
UK Business
Until the introduction of the New Electricity Trading Arrangements ("NETA") on 27 March 2001, almost all electricity sold in England & Wales had to be sold to the Pool, and electricity suppliers including Manweb had likewise to buy electricity from the Pool for resale to their customers. ScottishPower participated in the Pool during the year by exporting/ importing electricity to/from England & Wales via the interconnector. The Pool was operated under a Pooling and Settlement Agreement to which all licensed generators and suppliers of electricity in Great Britain were party.

The group had procedures in place to minimise exposure to Pool price variations, that is, the possibility that a change in Pool prices would reduce the proceeds of electricity sold to the Pool or increase the cost of electricity purchased from the Pool. These procedures involved SPUK and its subsidiary Manweb entering into CfDs. In general, the terms of CfDs are such that contracts are settled monthly (or more frequently) in arrears by reference to actual half-hourly Pool prices. During the year ended 31 March 2001, around 90% of the group's exposure to Pool prices was hedged in this way.

NETA was introduced in England & Wales to replace the Pool. NETA is a new wholesale market, comprising trading between generators and suppliers of electricity in England & Wales under which bulk electricity will be traded forward through bilateral contracts and one or more screen based power exchanges. NETA will be operated under the Balancing and Settlement Code to which all licensed generators and suppliers of electricity in Great Britain are party.

The balancing mechanism, operated from 3 1/2 hours ahead of real-time up to real-time, by the National Grid Company, will be 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' notified contract positions and their actual physical energy flows.

The group has also entered into some longer-term (in excess of one year) arrangements to protect against the volatility of electricity prices. These arrangements have the potential to be increased as the business grows and the time period covered will be reviewed on an ongoing basis.

The group also has procedures in place to minimise exposure to gas price variations. Gas price risk is managed through the use of a combination of longer-term (in excess of one year) contracts, contracts with flexible delivery profiles and using the flexibility within our portfolio of gas storage and generation assets.

Cover is built up throughout the year and at 31 March 2001 a significant proportion of the group's exposure to electricity and gas price variations for the following financial year is covered.

The group controls credit risk arising from its energy trading activities through credit approvals, counterparty credit limits and monitoring procedures.

US Business
PacifiCorp's market risk to commodity price change is primarily related to its electricity purchases and sales arising principally from its electric 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. Risk limits are established to govern energy purchases and sales. 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. Electricity futures contracts are utilised 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.

PacifiCorp has been experiencing the adverse effect of higher market prices due to inadequate generating capacity in the Western System Coordinating Council ("WSCC"), generating facility outages in the WSCC, including the unscheduled outage of PacifiCorp's Hunter generation unit from 24 November 2000 until 30 April 2001, lower hydro availability, high natural gas prices and increases in demand throughout the WSCC due in large part to economic growth which materially impacted the cost of meeting PacifiCorp's system load requirements. 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. If current market conditions continue, prices paid by PacifiCorp to provide certain load balancing resources to supply its load may continue to exceed the amounts it receives through retail rates and wholesale prices. PacifiCorp has filed applications seeking deferred accounting treatment for net power costs that varied from costs included in determining retail rates in the states of Utah, Oregon, Wyoming and Idaho. Approval of certain cost deferrals has been received in these states, and PacifiCorp is working with the commissions in these states to develop mechanisms for the recovery of these cost deferrals. Approval of deferred accounting treatment mitigates a portion of the price risk, assuming that recovery mechanisms are implemented.

PacifiCorp, along with other utilities in the western US, has been promoting conservation as a method to ease the current and potential future energy shortage. Actions have been initiated to pay industrial and commercial electricity users to forego power consumption by shutting down their operations so that power could be redistributed to other uses and residential customers. PacifiCorp is also addressing supply and demand issues through contracting power from customer-owned generation, providing consumer education about conservation, working with regulators to develop rate structures to promote conservation and providing monetary incentives to customers for reduction in usage. These actions along with increasing prices paid by customers for power may reduce the rate of electricity consumption.

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.

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 2001 for its UK businesses and US business were 33 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.

Accounting Developments
During the past year, the UK Accounting Standards Board ("ASB") issued three new standards.

FRS 17 'Retirement benefits' introduces radical changes to accounting for pensions and similar benefits, although its measurement rules are not required to be implemented in ScottishPower's Accounts until the year ending 31 March 2004. The requirements of the standard are currently being reviewed.

FRS 18 'Accounting policies' requires that companies adopt the accounting policies most appropriate to its particular circumstances, that these policies are reviewed regularly to ensure they remain appropriate and are changed when a new policy becomes more appropriate. The directors have reviewed the group's accounting policies and believe them to be the most appropriate to the group's circumstances.

FRS 19 'Deferred tax' makes significant changes to accounting for deferred tax in the UK. Previously deferred tax was accounted for on the partial provisioning basis required by Statement of Standard Accounting Practice 15. The new standard requires full provision to be made for deferred tax, with certain exceptions. This new standard has been implemented in preparing this year's Accounts and comparative figures have been restated accordingly. The effect of this change in accounting policy is set out in Note 6 to the Accounts.

A number of accounting pronouncements were issued during the past year by the Urgent Issues Task Force committee of the ASB. None of these pronouncements had any material impact on the group's results or financial position.

Details of new accounting pronouncements issued in the US, which will impact on our future results in accordance with US Generally Accepted Accounting Principles ("GAAP"), are set out in Note 35 . Our US GAAP results for future financial years could be materially impacted by Statement of Financial Accounting Standard 133 'Accounting for derivatives instruments and hedging activities'.

European Economic and Monetary Union and the Impact of the euro
European Economic and Monetary Union ("EMU") commenced on 1 January 1999 with the introduction of a new currency, the euro.

The group's businesses are almost totally UK and US focused, with very few sales or purchases denominated in currencies other than sterling or US dollars. As a result, while the UK remains outside EMU, the group will be affected to only a very minor extent by the introduction of the euro.

The benefits of a new integrated capital market have been recognised and the group has already issued commercial paper and medium term notes in euros.

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 35 to the Accounts. Under US GAAP the profit for the year ended 31 March 2001 was £387 million compared to £881 million in the previous year, before charging an extraordinary item, net of tax, of £11 million. Earnings per share under US GAAP, excluding extraordinary items, were 21.13 pence per share compared to 63.39 pence per share in 1999-00. In accordance with US GAAP, earnings per share are stated based on US GAAP earnings, without adjustments for the impact of the exceptional items, other than those which are classified as extraordinary items under US GAAP, and goodwill amortisation. The inclusion of exceptional items, other than those which are classified as extraordinary items under US GAAP, in the determination of earnings per share in accordance with US GAAP increased earnings by £409 million or 29.43 pence per share in 1999-00. The inclusion of goodwill amortisation decreased earnings by £164 million or 8.93 pence per share in 2000-01 and by £75 million or 5.38 pence per share in 1999-00.

Equity shareholders' funds under US GAAP amounted to £7,463 million at 31 March 2001 compared to £7,001 million at 31 March 2000.

Summary
These financial results have been impacted by the Hunter power station outage in Utah at a time of exceptional volatility in the western US power markets, and by the expected reductions in revenues resulting from the UK regulatory reviews. However, our underlying business performance has been good and we have taken a number of steps to sharpen our focus on improving shareholder value.

David Nish
Finance Director
3 May 2001

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Board of Directors

Executive Director Sir Ian Robinson (59) was Chief Executive from March 1995 until 17 April 2001; he retires from the Board on 4 May 2001. He was awarded a Knighthood in the Millennium New Year's Honours List for his services to the Electricity Industry. He was previously with Trafalgar House plc, where he was Chief Executive of John Brown and a main Board director. He is now Deputy Chairman of Hilton Group plc and Amey plc and a non-executive director of RMC Group plc. He also serves as Chairman of Scottish Enterprise, and previously chaired the Scottish Advisory Task Force on Welfare to Work. He is a Fellow of the Royal Academy of Engineering and a Fellow of the Institution of Chemical Engineers. Ian Russell (48) was appointed Chief Executive on 17 April 2001, having previously been appointed Finance Director in April 1994 and 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. Charles Berry (49) joined ScottishPower in November 1991, and was appointed to the Board in April 1999. He is Executive Director UK, responsible in this capacity for the UK energy businesses of Generation, Trading and Supply as well as regulatory matters. Previously he was Executive Director Customer Sales & Services. He will succeed Ian Russell as non-executive Chairman of Thus plc on 23 May 2001. He was previously Group Development Director of Norwest Holst, a subsidiary of Compagnie Général des Eaux, and prior to that held management positions within subsidiaries of Pilkington plc. David Nish (40) joined ScottishPower in September 1997 as Deputy Finance Director and was 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. On 23 May 2001 he will be appointed a non-executive director of Thus plc. Prior to joining ScottishPower, he was a partner with Price Waterhouse. 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. Alan Richardson (54) joined ScottishPower in July 1991 and was appointed to the Board in April 1999. In November 1999 he was appointed Chief Executive Officer of PacifiCorp upon completion of the merger. He is Executive Director US, with continuing responsibility for PacifiCorp and increased focus on the regulated and non-regulated energy value chains in the US. Between 1995 and April 1999 he was Managing Director Power Systems and, in that role, had responsibility for the Distribution businesses in Scotland and Manweb. He was previously director and General Manager of the Bushing Company Limited and Reyrolle Limited. He is a Fellow of the Institution of Electrical Engineers. Ken Vowles (59) joined ScottishPower in September 1990 and was appointed to the Board in September 1994 as Executive Director, Generation. He is Executive Director, International, with responsibility for the group's plant acquisition strategy and the company's overall operational effectiveness; he also has responsibility on a group-wide basis for safety and environmental matters and has led the company's European portal investment. He has over 30 years' experience of the power generation industry, having previously served with the Central Electricity Generating Board and National Power plc. He is a Fellow of the Institution of Electrical Engineers, a Fellow of the Institution of Mechanical Engineers and an Honorary Professor at Heriot Watt University. He is Chairman of the Electrical Industries Environmental Committee and a member of the Energy Saving Trust. For the purposes of the Annual Report on Form 20-F, the following are regarded as officers of the company.
Name	Title	Age	Date appointed to current post
Julian Brown	Group Director, Strategy	51	1 April 1997
Dominic Fry	Group Director, Corporate Communications	41	25 September 2000
Ronnie Mercer	Group Director, Infrastructure	57	1 April 2001
Andrew Mitchell	Company Secretary	49	1 July 1993
Paul Pagliari	Group Director, Human Resources	41	11 January 1999
James Stanley	Group Director, Legal	46	1 March 1996
Members of the Audit Committee John Parnaby, Chairman Sir Peter Gregson Allan Leighton Ewen Macpherson Robert Miller Charles Miller Smith Members of the Nomination Committee Charles Miller Smith, Chairman Mair Barnes Sir Peter Gregson Keith McKennon Ian Russell Members of the Remuneration Committee Ewen Macpherson, Chairman Euan Baird Mair Barnes Sir Peter Gregson Nolan Karras Keith McKennon John Parnaby Board Changes Euan Baird and Allan Leighton joined the Board on 8 January 2001. Sir Ian Robinson was succeeded by Ian Russell as Chief Executive on 17 April 2001. Sir Ian Robinson retires from the Board on 4 May 2001. In accordance with the Articles of Association, Euan Baird and Allan Leighton retire from office at the Annual General Meeting ("AGM") and, being eligible, offer themselves for election. In addition, Keith McKennon, Mair Barnes, John Parnaby and Ian Russell retire by rotation at the AGM. Mair Barnes and Ian Russell, being eligible, offer themselves for re-election. Keith McKennon and John Parnaby will retire from the Board at the conclusion of the AGM and do not accordingly seek re-election. Ian Russell has a service contract terminable by the company upon two years' notice.

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Board of Directors

Non-executive Directors

Charles Miller Smith (61) 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 since 1999 has been Chairman. He is also a non-executive director of HSBC, The Royal Scottish National Orchestra and a Member of the Court of Governors of Henley Management College.

Keith McKennon (67) joined the Board as Deputy Chairman in November 1999. He continues as a director of PacifiCorp, having previously (until the merger in November 1999) served as Chairman from 1994 and as President and Chief Executive Officer from 1998. Prior to joining PacifiCorp, he had a long career with Dow Chemical Company. He is a director of the Oregon Historical Society and a member of the Oregon State University President's Advisory Council. He will retire from the Board after the AGM in July 2001.

Euan Baird (63) 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 Haven Capital Management 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. His current term of office, subject to election in 2001, will expire at the AGM in 2004.

Mair Barnes (56) joined the Board in April 1998. She is a non-executive director of Abbey National plc, Patientline plc and the South African company, Woolworths Holdings Limited, and also a non-executive member of the Departmental Board of the Department of Trade and Industry. She was previously Managing Director of Woolworths plc in the UK until 1994, and then chaired Vantios plc and General Optica Limited until 1998 and 2000 respectively; she was also formerly a non-executive director of George Wimpey plc. Her current term of office, subject to reelection in 2001, will expire at the AGM in 2004.

Sir Peter Gregson GCB (64) joined the Board in December 1996 and is the company's senior independent non-executive director. 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 was a non-executive director of Woolwich plc and is Deputy Chairman of the Board of Companions of the Institute of Management. His current term of office expires at the AGM in 2003.

Nolan Karras (56) 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 and American General Savings Bank. 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 expires at the AGM in 2003.

Allan Leighton (48) joined the Board in January 2001. He was previously Chief Executive of Asda Group, and latterly President and Chief Executive Officer of Wal-Mart Europe, until November 2000. Since then, he has developed a diverse portfolio of business interests; in particular, he is Chairman of BhS, Lastminute.com and Wilson Connolly Holdings, Deputy Chairman of Leeds Sporting plc and a non-executive director of several other companies, including BSkyB, Consignia, Dyson and George Weston. He also chairs Race for Opportunity. His current term of office, subject to election in 2001, will expire at the AGM in 2004.

Ewen Macpherson (59) joined the Board in September 1996 and is Chairman of the Remuneration 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, Pantheon International Participations plc and Sussex Place Investment Management Limited. He is also Chairman of the Trustees of Glaxo-Wellcome Pension Fund. Previous appointments include Chairman of Glynwed International plc and non-executive director of Booker plc and The Law Debenture Corporation plc. His current term of office expires at the AGM in 2003.

Robert Miller (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 Finance Committee. He became Chairman and Chief Executive Officer of Rite-Aid Corp in December 1999, having previously been Vice-Chairman of the Kroger Company from May to December 1999 and, prior to that, President and Chief Executive Officer of Fred Meyer, Inc., since 1997, and Chairman since 1991. His current term of office expires at the AGM in 2003.

John Parnaby CBE (63) joined the Board in September 1994 and is Chairman of the Audit Committee. He retired in October 1997 as Group Director of Lucas Varity plc after 15 years, initially with Lucas Industries plc, and then as Sector Chief Executive and Group Director – Technology. He is Chairman of Knowledge Process Software plc and Think Digital plc and a member of the Council of Aston University. He is also a member of the Board of the UK Government Innovative Manufacturing Initiative. He has been a non-executive director of Jarvis plc and Molins plc and is a past President of the Institutions of Electrical Engineers and Manufacturing Engineers and a former member of the Council of the Royal Academy of Engineering. He will retire from the Board after the AGM in July 2001.

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Corporate Goverance

Corporate Governance Statement
The company is committed to the highest standards of corporate governance. This statement together with the Remuneration Report of the Directors , describes how, in the course of the financial year ended 31 March 2001, 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 six executive and ten 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.

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Corporate Goverance

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 is chaired by John Parnaby (his successor in July 2001 will be Ewen Macpherson). 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 for 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 is chaired by Ewen Macpherson (his successor in July 2001 will be Sir Peter Gregson). 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 2000-01 is set out here .

Executive Team
The Executive Team comprises the Chief Executive and other executive directors, together with the Group Director, Infrastructure; Group Director, Corporate Communications; Group Director, Human Resources; Group Director, Legal; Group Director, Strategy; and the 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.

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Corporate Goverance

Internal Control
The directors of ScottishPower have overall responsibility for the system of internal control and for reviewing the effectiveness of the system. The system of internal control 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.

The risk management framework adopted by the group is designed to ensure that key controls are embedded into business processes. The continued development and implementation of the risk management and internal control system across the group has allowed the directors to comply with the Combined Code provisions on internal control in the course of the financial year ended 31 March 2001.

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. These risks are then mapped against the key business processes in place and the controls embedded within the business process are then identified to manage the risk exposure. Any key actions needed to further enhance the control environment are identified along with the person responsible for the management of the specific risk. All of this information is held in a series of Business Risk and Control Frameworks, which are fully reviewed and updated on a continuous basis.

In addition to the full review of the Business Risk and Control Frameworks described above, each month a review of the key risks, controls and action plans within each of the businesses takes place and a Risk Report is produced for review 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.

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 Executive Team on a monthly basis receives the group-wide Risk Report for review. This report highlights the most significant risks across the group, the actions being taken to mitigate these and also identifies individuals responsible for the management of these risks.

Business Control 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 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 Executive Team, 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 control.

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 control during the year.

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 Head 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.

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Remuneration Report of the Directors

Remuneration Committee
The Board is responsible for determining the remuneration policy for the group. The Remuneration Committee determines the detail of remuneration arrangements for executive directors and reviews proposals in respect of other senior executives.

The Remuneration Committee consists solely of independent non-executive directors. Its members, who have no personal financial interest, other than as shareholders, in the matters considered by the Committee, are Ewen Macpherson (Chairman), Euan Baird, Mair Barnes, Sir Peter Gregson, Nolan Karras, Keith McKennon and John Parnaby. The Committee is advised internally and is also provided with independent advice from external remuneration consultants in order to assist in determining and developing its policies.

Committee members are paid a fee and expenses, but do not receive any other remuneration from the company. Details of the remuneration of all non-executive directors are set out in Table 28 . The Committee's policy and disclosures on directors and senior management remuneration are set out below.

Following the flotation of Thus plc in November 1999, 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.

Executive Remuneration Philosophy
The company's remuneration philosophy is to ensure that the rewards for executives and directors attract and retain executives of high quality, who have the requisite skills and are incentivised to achieve performance which exceeds that of competitor companies. Furthermore, the objective is to ensure that incentive schemes are in line with best practice and promote the interests of shareholders.

The Committee considers a Personal Shareholding Policy for executives and senior managers to be in the best interests of shareholders. Accordingly, the company introduced a Personal Shareholding Policy last year, further aligning the interests of executives and senior managers with those of shareholders. In conjunction with the proposals being put to the Annual General Meeting, it is proposed to increase the levels of personal shareholding required under this Policy.

Competitiveness of Remuneration
The Committee believes that to attract and retain key executives of high calibre, the remuneration package it offers must be market-competitive. The remuneration strategy is to adopt a mid-market position on all senior management remuneration packages, and to provide packages above the mid-market level only where supported by demonstrably superior personal performance. As the company evolves and establishes a presence in new business sectors, remuneration packages will be developed to reflect the prevailing market practice in each business environment. This positioning will be established drawing upon advice from independent remuneration consultants and internal advisers.

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

Remuneration Policy
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. After careful consideration, the Committee is of the view that the stated remuneration policy is appropriate. In line with its objectives to build international business, the company has recruited a number of executives with key business skills, and hence a reward structure broadly equivalent to other large UK-listed companies with international operations is necessary.

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 2000-01 scheme for executive directors provided a bonus 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 and performance against these is reviewed on a six-monthly basis.

Two-thirds of any bonus payment will be paid in cash and the remaining one-third will be paid in shares, receipt of which will be deferred for a three-year period.

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Remuneration Report of the Directors

Executive Share Schemes
The company operates a Long Term Incentive Plan ("LTIP") 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 performance measures are met. These relate to the sustained underlying financial performance of the company and customer service standards, including those set by Ofgem and OFWAT.

 

The number of shares which vest is dependent upon the company's comparative total shareholder return performance, over a three-year performance period.

A number of share-based incentive schemes 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.

It is some five years since the current LTIP was introduced and since then there have been significant changes in both UK market practice and the structure and scale of the business. Some 49% of the company's revenues are now generated in the US.

In the Merger Agreement, shareholders approved the continuation of PacifiCorp's compensation, incentive and employee benefit plans and arrangements for a period of two years after the merger date. The company was required to ensure that PacifiCorp's arrangements were no less favourable in the aggregate to the employee for the same period post-merger. This period expires in November 2001.

The Board believes the company should have in place incentive plans that are competitive for senior executives with international responsibilities and which reflect local market practice. The Remuneration Committee acknowledges that, taken in conjunction with a Personal Shareholding Policy, executive share options are the most beneficial way of aligning employee interests with shareholder interests. Executive share options, particularly in the US, are the most prevalent form of long-term incentive. The Board is of the view that it is desirable to have such plans in place.

Given the international dimension of the company and, in particular, the need to take account of market conditions in the US, approval for the introduction of a new Executive Share Option Plan is being sought at the forthcoming Annual General Meeting. This will bring the long-term incentive arrangements more into line with those operated by other major UK companies with international activities.

Inland Revenue approval will be sought for the approved part of the Executive Share Option Plan. Executive directors and senior managers of participating companies within the group, whether employed in the UK or overseas, may be eligible to participate, subject to the rules of the new Plan.

Employee Share Schemes
The company operates a savings-related share option scheme, which is open to all UK-based 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 on 28 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-based 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 and, last year, the company offered employees an initial grant of 50 Shares to launch the ESOP.

Pension
The executive directors, and other senior management of the company, are provided 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 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 2001 was £500,000.

The Trustee body of the Executive Top Up Plan is chaired by the 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 2000-01.

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. The company provides all levels of UK staff, including executive directors and certain pensioners, with a discount on merchandise sold by its Appliance Retailing business.

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Remuneration Report of the Directors

Service Contracts
Existing executive directors appointed before 1 April 1999, have service contracts terminable by the company on two years' notice (prior to September 1994 notice periods were three years) and by the individuals concerned on one year's notice. The Committee believes that it remains appropriate for these executive directors to continue to be on two-year rolling contracts. Executive directors, Charles Berry, David Nish and Alan Richardson, 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.

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.

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 28 .

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, as a group, was £3,615,392.

During 2000-01 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 £1,177,900.

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.

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 Executive and Sharesave Schemes and awards under the LTIP, are shown in Table 30 and Table 31 .

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 28 provides a breakdown of the total emoluments of the Chairman and all the directors in office during the year ended 31 March 2001.

Directors' Pension Benefits
Details of pension benefits earned by the executive directors during the year are shown in Table 29 .

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Remuneration Report of the Directors

Table 28 –Directors' Emoluments 2000–01
	Basic salary £	Bonus £	Deferred bonus £	Benefits in kind £	Total 2001 £	Total 2000 £
Chairman and executive directors
Murray Stuart (retired 31 March 2000)	–	–	–	–	–	229,630
Charles Miller Smith (appointed 1 August 1999, appointed Chairman 1 April 2000)	235,000	–	–	4,731	239,731	42,794
Sir Ian Robinson	522,668	–	–	24,194	546,862	688,611
Ian Russell	390,000	–	–	34,571	424,571	628,497
Charles Berry	220,000	–	–	19,292	239,292	274,960
David Nish (appointed 13 December 1999)	225,000	–	–	28,022	253,022	90,742
Alan Richardson*	245,000	–	–	704	245,704	295,361
Ken Vowles	270,000	–	–	14,110	284,110	368,708
Duncan Whyte (resigned 31 May 1999)	–	–	–	–	–	41,682
	2,107,668	–	–	125,624	2,233,292	2,660,985
Non-executive directors (fees and expenses)
Keith McKennon (appointed 30 November 1999)	64,000	–	–	11,033	75,033	32,775
Euan Baird (appointed 8 January 2001)	6,548	–	–	–	6,548	–
Mair Barnes	33,000	–	–	2,758	35,758	30,997
Sir Ronald Garrick (retired 30 April 1999)	–	–	–	–	–	2,958
Sir Peter Gregson	36,500	–	–	2,067	38,567	34,912
Nolan Karras (appointed 30 November 1999)**	33,500	–	–	6,542	40,042	19,881
Allan Leighton (appointed 8 January 2001)	6,548	–	–	362	6,910	–
Ewen Macpherson	39,500	–	–	2,202	41,702	38,507
Robert Miller (appointed 30 November 1999)	31,500	–	–	20,967	52,467	9,243
John Parnaby	40,500	–	–	1,939	42,439	39,623
Total	2,399,264	–	–	173,494	2,572,758	2,869,881

Other emoluments – executive directors
*	Alan Richardson received an additional £283,220 (2000 £124,300) in respect of housing, foreign service allowance and other essential costs associated with his assignment as President & CEO, PacifiCorp based in the US.
**	Nolan Karras received emoluments in the US of £26,857 (2000 £nil) in respect of services to the PacifiCorp and Utah advisory boards in the form of cash and shares.
The emoluments of the highest paid director (Sir Ian Robinson) excluding pension contributions were £546,862 (2000 £688,611). In addition, gains on exercise of share options during the year by Sir Ian Robinson amounted to £17,301 (2000 £nil). Details of other share related incentives are contained in Tables 30 and 31. Pensions contributions made by the company under approved pension arrangements for Sir Ian Robinson amounted to £nil (2000 £nil). Sir Ian Robinson also has an entitlement under the unapproved pension benefits described further in Table 29 , note (iii) below. The total liabilities for the 15 executives and senior employees arising in relation to unapproved benefits for service for the year to 31 March 2001 was £500,000 (2000 £600,000). All benefits for the above are provided on a defined benefit basis.

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Renumeration Report of the Directors

Table 29 – Defined Benefits Pension Scheme 2000–01
	Transferred in benefits £	Additional pension earned in the year £	Accrued entitlement £	Transfer value of increases after indexation (net of directors' contribution) £
Chairman and executive directors
Charles Miller Smith	–	–	–	–
Sir Ian Robinson (Note i)	148,426	54,524	288,008	996,899
Ian Russell	10,703	16,024	91,908	188,318
Charles Berry	–	13,014	60,173	156,832
David Nish	23,740	15,165	44,079	136,385
Alan Richardson	–	22,436	79,183	329,089
Ken Vowles	115,027	8,034	166,500	132,967

(i)	The accrued entitlement of the highest paid director (Sir Ian Robinson) was £319,200 (2000 £226,904). The figures shown in the table above relate to Sir Ian's accrual of pension over the year on the basis of his contract in force at the start of the year. In addition, following a change to his contract, his pension earned in the year increased by a further £31,192 per annum with an added value of £854,263. The agreed change to his contract of employment was to allow Sir Ian to retire on his promised pension on 31 May 2001, being one year prior to his Normal Pension Date.
(ii)	The pension entitlement shown is that which would be paid annually on retirement based on 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.
(iii)	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. Full details are included in the Remuneration Report. The pension benefits disclosed above include approved and unapproved pension arrangements.
(iv)	The increase in accrued pension during the year allows for an increase in inflation of RPI as measured at December 2000 (2.9%).
(v)	The transfer value has been calculated on the basis of actuarial advice in accordance with Actuarial Guidance Note GN11, less directors' contributions.
(vi)	Transferred in benefits represent pension rights accrued in respect of previous employments.

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Remuneration Report of the Directors

Table 30 –Directors' Interests in Shares as at 31 March 2001

Ordinary shares

Share options (Executive)

Share options (Sharesave)

Long Term Incentive Plan

31.3.01

1.4.00 (or date of appointment if later)

31.3.01

1.4.00

31.3.01

1.4.00

31.3.01

1.4.00

**Vested

*Potential

**Vested

*Potential

Charles Miller Smith

11,000

11,000

–

–

–

–

–

–

–

–

Sir Ian Robinson

•74,113

67,412

–

–

–

6,581

76,455

146,996

36,072

142,689

Ian Russell

•58,418

25,912

–

–

–

–

27,691

114,694

27,055

106,617

Charles Berry

•14,691

3,520

–

–

2,232

2,232

9,951

55,461

9,420

43,346

David Nish

•4,112

2,250

–

–

2,215

2,215

–

45,286

–

22,210

Alan Richardson

•10,660

5,107

–

1,450

3,141

4,457

20,477

55,824

9,661

44,863

Ken Vowles

•138,801

119,327

–

–

5,501

5,501

20,768

81,655

19,324

78,194

Keith McKennon

121,580

111,462

†580,000

†580,000

–

–

–

–

–

–

Euan Baird (appointed 8 Jan 2001)

100,000

–

–

–

–

–

–

–

–

–

Mair Barnes

1,400

1,400

–

–

–

–

–

–

–

–

Sir Peter Gregson

1,024

975

–

–

–

–

–

–

–

–

Nolan Karras

27,347

15,331

–

–

–

–

–

–

–

–

Allan Leighton (appointed 8 Jan 2001)

–

–

–

–

–

–

–

–

–

–

Ewen Macpherson

5,000

5,000

–

–

–

–

–

–

–

–

Robert Miller

9,994

9,994

–

–

–

–

–

–

–

–

John Parnaby

7,218

7,002

–

–

–

–

–

–

–

–

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.
†	On 9 February 1999, PacifiCorp granted to Keith McKennon under the PacifiCorp Stock Incentive Plan, stock options to acquire 250,000 shares of PacifiCorp Common Stock at an option price of $19 with a three-year vesting period (commencing one year after the grant date) and a ten-year exercise period. Following the completion of the merger with PacifiCorp, these options were converted to options to acquire 145,000 ScottishPower ADSs. One ScottishPower ADS equates to four ordinary shares and therefore the option, expressed in ordinary shares, is over 580,000 ordinary shares.
	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	Dividends shares	Total
Sir Ian Robinson	–	50	50	–	100
Ian Russell	50	50	50	1	151
Charles Berry	50	50	50	1	151
David Nish	50	50	50	1	151
Alan Richardson	–	50	50	–	100
Ken Vowles	50	50	50	–	150
Between 31 March 2001 and 3 May 2001 each of the executive directors (Sir Ian Robinson, Ian Russell, Charles Berry, David Nish, Alan Richardson, Ken Vowles) acquired 27 Partnership Shares and 27 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 2001 and 3 May 2001.

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Remuneration Report of the Directors

	Table 31 –Directors' Interests in Performance and Other Share Plans as at 31 March 2001
		1 April 2000	Granted	Exercised	Lapsed#	31 March 2001	Option exercise price (pence)	Date exercised	Market price at date of exercise (pence)	Date from which exercisable	Expiry date
	Long Term Incentive Plan
	Sir Ian Robinson	36,072	–	–	–	36,072	nil			9 Aug 00	8 Aug 03
		53,846	–	–	13,463	40,383	nil			16 May 01	15 May 04
		41,916	–	–	–	41,916	nil			7 May 02	6 May 05
		46,927	–	–	–	46,927	nil			10 May 03	9 May 06
			58,153	–	–	58,153	nil			5 May 04	4 May 07
		178,761	58,153	–	13,463	223,451
	Ian Russell	27,055	–	27,055	–	–	nil	18 Aug 00	536.25	9 Aug 00	8 Aug 03
		36,923	–	–	9,232	27,691	nil			16 May 01	15 May 04
		31,706	–	–	–	31,706	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
		133,672	45,000	27,055	9,232	142,385
	Charles Berry	9,420	–	9,420	–	–	nil	8 Sept 00	496.75	9 Aug 00	8 Aug 03
		13,269	–	–	3,318	9,951	nil			16 May 01	15 May 04
		11,083	–	–	–	11,083	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
		52,766	25,384	9,420	3,318	65,412
	David Nish	–	–	–	–	–	nil			9 Aug 00	8 Aug 03
		–	–	–	–	–	nil			16 May 01	15 May 04
		10,479	–	–	–	10,479	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
		22,210	23,076	–	–	45,286
	Alan Richardson	9,661	–	–	–	9,661	nil			9 Aug 00	8 Aug 03
		14,423	–	–	3,607	10,816	nil			16 May 01	15 May 04
		11,446	–	–	–	11,446	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
		54,524	25,384	–	3,607	76,301
	Ken Vowles	19,324	–	19,324	–	–	nil	9 Aug 00	546.75	9 Aug 00	8 Aug 03
		27,692	–	–	6,924	20,768	nil			16 May 01	15 May 04
		22,570	–	–	–	22,570	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
		97,518	31,153	19,324	6,924	102,423
	On 9 August 2000, the first awards under the Long Term Incentive Plan became exercisable. The mid-market closing price on that day was 548 pence and the value attributable to those awards at that date was £556,395. Details of awards excercised are shown in the table above.
#	During the year, the performance period for awards granted under the Long Term Incentive Plan in 1997 ended and, on the basis of the company's totalshareholder return, 25% of shares under awards lapsed and 75% 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. Footnote Awards made to directors under the Long Term Incentive Plan on 4 May 2001 were as follows: Ian Russell 92,075; Charles Berry 43,526; David Nish 50,223; Alan Richardson 50,223; Ken Vowles 50,223.

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Remuneration Report of the Directors

Table 31 – Directors' Interests in Performance and Other Share Plans as at 31 March 2001 (continued)
	1 April 2000	Granted	Exercised	Lapsed#	31 March 2001	Option exercise price (pence)	Date exercised	Market price at date of exercise (pence)	Date from which exercisable	Expiry date
Executive Share Option Scheme
Alan Richardson	1,450	–	1,450	–	–	454.8	28 Nov 00	545	17 Dec 96	16 Dec 03
PacifiCorp Stock Incentive Plan †
Keith McKennon	580,000	–	–	–	580,000	575.9			9 Feb 03	9 Feb 09

† On 9 February 1999, PacifiCorp granted to Keith McKennon under the PacifiCorp Stock Incentive Plan, stock options to acquire 250,000 shares of PacifiCorp Common Stock at an option price of $19 with a three-year vesting period (commencing one year after the grant date) and a ten-year exercise period. Following the completion of the merger with PacifiCorp, these options were converted to options to acquire 145,000 ScottishPower ADSs. One ScottishPower ADS equates to four ordinary shares and therefore the option, expressed in ordinary shares, is over 580,000 ordinary shares. The ADS option price of $32.76 has been divided by the ADS ratio of four and converted to sterling at the closing exchange rate on 31 March 2001.

Sharesave Scheme
Sir Ian Robinson	6,581	–	6,581	–	–	262.1	29 Sept 00	525	1 Sept 00	28 Feb 01
Charles Berry	1,329	–	–	–	1,329	440.0*			1 Sept 01	28 Feb 02
	903	–	–	–	903	429.0*			1 Sept 02	28 Feb 03
	2,232	–	–	–	2,232
David Nish	2,215	–	–	–	2,215	440.0*			1 Sept 01	28 Feb 02
Alan Richardson	1,316	–	1,316	–	–	262.1	29 Sept 00	525	1 Sept 00	28 Feb 01
	1,568	–	–	–	1,568	440.0			1 Sept 03	29 Feb 04
	1,573	–	–	–	1,573	429.0			1 Sept 04	28 Feb 05
	4,457	–	1,316	–	3,141
Ken Vowles	3,933	–	–	–	3,933	263.1			1 Sept 01	28 Feb 02
	1,568	–	–	–	1,568	440.0			1 Sept 03	29 Feb 04
	5,501	–	–	–	5,501

*	Denotes options granted under a three–year scheme
(i)	The market price of the shares at 31 March 2001 was 468 pence and the range during 2000-01 was 422 pence to 576 pence.
(ii)	The Long Term Incentive Plan supersedes the Executive Share Option Scheme, and annual awards to acquire shares in ScottishPower at nil or nominal cost are made 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. 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 fourth year up to the seventh year after the grant of the award. No dividends accrue to participants prior to vesting.
(iii)	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.
(iv)	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 to five years under an Inland Revenue approved savings contract, subject to a current maximum.
(v)	Total gains made on exercise of directors' share options and awards during the year were £319,599 (2000 £42,796).

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Remuneration Report of the Directors

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 2001. 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

Andrew Mitchell
Secretary
3 May 2001

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Renumeration Report of the Directors

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 and any rules, regulations or releases of the Securities and Exchange Commission with respect thereto (the "PSLRA"). Forward-looking statements in this document include, but are not limited to, statements in: "Chief Executive's Review" relating to ScottishPower's intent to focus squarely on the energy market, plans to pursue selective acquisitions, cost savings from measures implemented in the Infrastructure Division, and objectives to reduce operating costs, capital investment and the workforce, the development and the commencement of operation of new plants, the expectation of exceeding targeted amounts of renewable energy in the Pacific Northwest, goals for wholesale energy trading, reductions in CO2/KWh; "Business Review – US Division" relating to plans to expand energy business, 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, the approval process for US restructuring, forecasts for average annual growth in retail megawatt hour sales for the period from 2002 to 2005, and PacifiCorp's expectations regarding the effect of deregulation; "Business Review – UK Division" relating to the development of windfarms, the ability of ScottishPower's UK power stations to support generation output and timing of the upgrade of the Scotland-England transmission link and the commencement of operation of the Scotland-Northern Ireland interconnector; "Business Review – Infrastructure Division" relating to estimates for Southern Water's investment programme; "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, as well as the impact of compliance costs; "Business Review – Regulation of the Electricity Industry in the UK" relating to the possible adjustment of ScottishPower's and Manweb's revenues resulting from the DGES revenue and output matching project; "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, and the effect of requirements and fines on Southern Water by the Environmental Agency; "Financial Review – Capital Expenditure and Cash Flow (2000-01)" relating to the description of new sources of power; "Financial Review – Financial Instruments and Risk Management" relating to the belief that the group is not exposed to any material concentration of credit risk; "Financial Review – Accounting Developments" relating to the impact on future US GAAP results for upcoming financial years; "Financial Review – European Economic and Monetary Union and the impact of the euro" relating to limited effect of the introduction of the euro on ScottishPower's businesses; 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.

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

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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.

The business segments of the group are defined as follows:

United Kingdom
Generation Wholesale
The generation of electricity from the group's own power stations, the purchase of external supplies of energy for sale to other business segments of the group and the sale of electricity to other public electricity suppliers, to the Pool in England & Wales and, since 27 March 2001, full participation in the New Electricity Trading Arrangements (NETA) in England & Wales.

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 England & Wales through the Anglo-Scottish Interconnector.

Energy Supply
The sale of energy to customers, together with related billing and collection activities.

Southern Water
The provision of water and wastewater services in the south-east of England, together with related billing and collection activities.

Telecoms
The provision of telecommunications services, Internet access and information services to national corporates, small and medium-sized enterprises and residential customers. For the year ended 31 March 2001 this segment comprised Thus plc. In previous years 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.

Other
The retailing and servicing of domestic electrical goods and home entertainment appliances, corporate services, generation gas trading and the businesses of the company's other UK subsidiary undertakings. In addition it included the provision of electrical contracting and consultancy services prior to the disposal of the group's Contracting Services and Technology businesses during the year ended 31 March 2001.

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Accounting Policies and Definitions

United States
PacifiCorp
A vertically integrated electric utility that includes the generation, transmission and distribution and sale of electricity to retail customers in portions of six western states; Utah, Oregon, Wyoming, Washington, Idaho and California. The state regulatory commissions and Federal Energy Regulatory Commission (FERC) regulate the retail and wholesale operations. The operations also include wholesale sales and purchase transactions with various entities. It also includes businesses of other US subsidiaries not regulated as electric utilities in the US. During the year ended 31 March 2001, the former PacifiCorp Domestic Electric and PacifiCorp Other business segments were combined to form a PacifiCorp business segment as the directors considered that the activities of the PacifiCorp Other segment were not material.

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, telecommunications services, electrical contracting and consultancy 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 centralised services and rates.

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.

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Accounting Policies and Definitions

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 35 .

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 major 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.

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Accounting Policies and Definitions

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.

Interest rate swaps/Forward rate agreements
These are used to manage 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
These are used to limit interest rate exposures. Premiums received and payable on these contracts are amortised over the period of the contracts and are disclosed as interest income and expense.

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. 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.

Premiums and discounts
Premiums and discounts arising on the early repayment of borrowings are written off to the profit and loss account as incurred.

Contracts for Differences (CfDs)
The group's objectives, policies and strategy for holding CfDs are outlined in the Financial Review.

The group used CfDs during the year to minimise exposure to Pool price variations in England & Wales. A CfD is a contract between two parties (e.g. a generator and a public electricity supplier) that requires each party to make or receive payments over a specific term based on the difference between an agreed price (i.e. the bilaterally determined strike price) and a price that varies with a specified commodity index (i.e. the Pool), applied to an agreed quantity (i.e. a number of MWhs). The average duration for such contracts is approximately one year. The group's use of such derivative instruments during the year related directly to the underlying purchase and sale of electricity to and from the Pool.

The cost or income attributable to CfDs has been recorded in the accounting records when settlement was made. Where delivery under the CfD has taken place prior to the period end, adjustments are made to account for the known variances between the contract strike price and the Pool price on the date of delivery.

With the introduction of NETA on 27 March 2001, the majority of CfDs have been translated into bilateral contracts for the physical delivery or receipt of energy in England & Wales. The quantities to be delivered or received equate to the volumes and time periods covered by the former CfD and the amount payable or receivable is equivalent to the strike price within the CfD.

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Accounting Policies and Definitions

Taxation
The charge for ordinary taxation is based on the profits for the year and takes into account full provision for deferred tax, using the approach set out in Financial Reporting Standard 19 'Deferred tax', in respect of timing differences on a non-discounted basis. Such timing differences arise primarily from the differing treatment for taxation and accounting purposes of provisions and depreciation of fixed assets. Previously the provision for deferred tax was accounted for on the partial provisioning basis required by Statement of Standard Accounting Practice (SSAP) 15. The effect of this change in accounting policy on the results and net assets on the current and previous financial years is disclosed in Note 6 .

Comparative figures have been restated in the Group Profit and Loss Account, the Balance Sheet and Notes.

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.

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Accounting Policies and Definitions

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, 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. 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.

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Accounting Policies and Definitions

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.

Long Term Incentive Plan
Shares in the company purchased for the Long Term Incentive Plan 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 Long Term Incentive Plan, 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.

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Accounting Policies and Definitions

Stocks
Stocks are valued at the lower of 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 United States 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 .

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Accounting Policies and Definitions

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.

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Accounting Policies and Definitions

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 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. 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 are taken directly to group reserves and are shown in the Statement of Total Recognised Gains and Losses. Exchange rates The exchange rates applied in the preparation of the Accounts were as follows:
	Year ended 31 March
Average rate for quarters ending:	2001	2000
30 June	$1.53/£	–
30 September	$1.48/£	–
31 December	$1.45/£	$1.62/£
31 March	$1.46/£	$1.61/£
Closing rate as at 31 March	$1.42/£	$1.60/£
A glossary of terms used in the Accounts and their US equivalents is set out here .

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Group Profit and Loss Account for the year ended 31 March 2001

	Notes	Total before exceptional items 2001 £m	Exceptional item 2001 (Note 4) £m			2001 £m	Total before exceptional items 2000 £m		Exceptional items 2000 (Note 4) £m			2000 £m		1999 £m
Turnover: group and share of joint ventures and associates		6,361.4		–		6,361.4		4,123.1		–		4,123.1		3,251.5
Less: share of turnover in joint ventures		(11.7	)	–		(11.7	)	(7.6	)	–		(7.6	)	(7.3	)
Less: share of turnover in associates		(0.4	)	–		(0.4	)	(0.5	)	–		(0.5	)	(1.9	)
Group turnover from continuing operations	1	6,349.3		–		6,349.3		4,115.0		–		4,115.0		3,242.3
Cost of sales		(4,407.4	)	(62.1	)	(4,469.5)		(2,424.7	)	(173.5	)	(2,598.2	)	(1,860.5	)
Gross profit from continuing operations		1,941.9		(62.1	)	1,879.8		1,690.3		(173.5	)	1,516.8		1,381.8
Transmission and distribution costs		(521.6	)	(45.1	)	(566.7	)	(350.9	)	(61.1	)	(412.0	)	(258.1	)
Administrative expenses		(628.1	)	(13.5	)	(641.6	)	(458.7	)	(24.4	)	(483.1	)	(348.8	)
Other operating income		50.4		–		50.4		40.3		–		40.3		27.9
Operating profit from continuing operations before goodwill amortisation		970.2		(120.7	)	849.5		961.4		(259.0	)	702.4		804.0
Goodwill amortisation		(127.6	)	–		(127.6	)	(40.4	)	–		(40.4	)	(1.2	)
Operating profit from continuing operations	1,2	842.6		(120.7	)	721.9		921.0		(259.0	)	662.0		802.8
Share of operating (loss)/profit in joint ventures		(9.4	)	–		(9.4	)	1.6		(3.3	)	(1.7	)	2.1
Share of operating profit in associates		0.1		–		0.1		0.1		–		0.1		0.2
		833.3		(120.7	)	712.6		922.7		(262.3	)	660.4		805.1
Gain on partial disposal of Thus		–		–		–		–		787.0		787.0		–
Loss on disposal of and withdrawal from operations		–		–		–		–		(55.0	)	(55.0	)	–
Profit on ordinary activities before interest		833.3		(120.7	)	712.6		922.7		469.7		1,392.4		805.1
Net interest and similar charges
– Group		(330.0	)	–		(330.0	)	(226.1	)	(15.9	)	(242.0	)	(160.8	)
– Joint ventures		(2.9	)	–		(2.9	)	(1.4	)	–		(1.4	)	(0.5	)
	5	(332.9	)	–		(332.9	)	(227.5	)	(15.9	)	(243.4	)	(161.3	)
Profit on ordinary activities before goodwill amortisation and taxation		628.0		(120.7	)	507.3		735.6		453.8		1,189.4		645.0
Goodwill amortisation		(127.6	)	–		(127.6	)	(40.4	)	–		(40.4	)	(1.2	)
Profit on ordinary activities before taxation		500.4		(120.7	)	379.7		695.2		453.8		1,149.0		643.8
Taxation – Group		(139.2	)	45.9		(93.3	)	(207.0	)	(56.0	)	(263.0	)	(174.5	)
– Joint ventures		(1.9	)	–		(1.9	)	0.1		–		0.1		(0.5	)
– Associates		–		–		–		–		–		–		(0.1	)
	6	(141.1	)	45.9		(95.2	)	(206.9	)	(56.0	)	(262.9	)	(175.1	)
Profit after taxation		359.3		(74.8	)	284.5		488.3		397.8		886.1		468.7
Minority interests	28	23.0		–		23.0		(1.1	)	–		(1.1	)	0.6
Profit for the financial year		382.3		(74.8	)	307.5		487.2		397.8		885.0		469.3
Dividends	8	(477.3	)	–		(477.3	)	(341.4	)	–		(341.4	)	(267.9	)
(Loss)/profit retained	27	(95.0	)	(74.8	)	(169.8	)	145.8		397.8		543.6		201.4
Earnings per ordinary share	7	20.89	p	(4.09	)p	16.80	p	35.06	p	28.63	p	63.69	p	39.60	p
Adjusting items – exceptional items		–		4.09	p	4.09	p	–		(28.63	)p	(28.63	)p	–
– goodwill amortisation		6.97	p	–		6.97	p	2.91	p	–		2.91	p	0.10	p
Earnings per ordinary share before exceptional items, goodwill amortisation and deferred tax		30.65	p	–		30.65	p	41.22	p	–		41.22	p	42.52	p
Effect of deferred tax		(2.79	)p	–		(2.79	)p	(3.25	)p	–		(3.25	)p	(2.82	)p
Earnings per ordinary share before exceptional items and goodwill amortisation	7	27.86	p	–		27.86	p	37.97	p	–		37.97	p	39.70	p
Diluted earnings per ordinary share	7					16.74	p					63.25	p	39.20	p
Adjusting items – exceptional items						4.07	p					(28.43	)p	–
– goodwill amortisation						6.94	p					2.89	p	0.10	p
Diluted earnings per ordinary share before exceptional items and goodwill amortisation	7					27.75	p					37.71	p	39.30	p
Dividends per ordinary share	8					26.04	p					24.80	p	22.50	p
The Accounting Policies and Definitions , together with the Notes 1 to 40 form part of these Accounts.

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Group Profit and Loss Account for the year ended 31 March 2001

	Note	2001 £m		2000 £m	1999 £m
Profit for the financial year		307.5		885.0	469.3
Exchange movement on translation of overseas results and net assets	27	493.1		24.9	–
Total recognised gains and losses for the financial year		800.6		909.9	469.3
Prior year adjustment for implementation of FRS 19 ‘Deferred tax’ (as explained in Note 6 )		(800.6	)
Total gains and losses recognised since last annual Accounts		–

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Reconciliation of Movements in Shareholders’ Funds for the year ended 31 March 2001

	2001 £m		2000 £m		1999 £m
Profit for the financial year	307.5		885.0		469.3
Dividends	(477.3	)	(341.4	)	(267.9
(Loss)/profit retained	(169.8	)	543.6		201.4
Exchange movement on translation of overseas results and net assets	493.1		24.9		–
Share capital issued	6.6		4,071.2		3.2
Share buy-back (including costs)	–		(302.0	)	–
Impairment of goodwill previously written off to reserves	–		7.5		–
Goodwill realised on disposals	–		15.3		–
Net movement in shareholders’ funds	329.9		4,360.5		204.6
Opening shareholders’ funds (as adjusted for implementation of FRS 19 ‘Deferred tax’)	5,563.3		1,202.8		998.2
Closing shareholders’ funds	5,893.2		5,563.3		1,202.8
The Accounting Policies and Definitions , together with Notes 1 to 40 form part of these Accounts.

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Group Profit and Loss Account for the year ended 31 March 2001

1 Segmental information
		Total turnover						Inter-segment turnover						External turnover
(a) Turnover by segment	Notes	2001 £m		2000 £m		1999 £m		2001 £m		2000 £m		1999 £m		2001 £m		2000 £m		1999 £m
United Kingdom
Generation Wholesale		798.8		884.6		914.3		523.1		626.8		695.3		275.7		257.8		219.0
Power Systems		652.2		728.5		716.9		439.6		555.9		615.5		212.6		172.6		101.4
Energy Supply		1,748.9		1,908.9		1,985.3		40.7		9.6		31.9		1,708.2		1,899.3		1,953.4
Southern Water		421.6		470.5		440.2		–		–		0.7		421.6		470.5		439.5
Telecoms	(i)	233.8		243.2		219.9		34.4		40.4		39.2		199.4		202.8		180.7
Other		729.1		756.5		613.1		319.6		356.2		264.8		409.5		400.3		348.3
United Kingdom total														3,227.0		3,403.3		3,242.3
United States
PacifiCorp	(ii)	3,122.3		711.7		–		–		–		–		3,122.3		711.7		–
United States total														3,122.3		711.7		–
Total	(iii)													6,349.3		4,115.0		3,242.3
	Before goodwill amortisation and exceptional item 2001		Goodwill amortisation 2001		Exceptional item 2001			2001	Before goodwill amortisation and exceptional items 2000		Goodwill amortisation 2000		Exceptional items 2000			2000		1999
(b) Operating profit/(loss) by segment	Note	£m		£m		£m		£m		£m		£m		£m		£m		£m
United Kingdom
Generation Wholesale		92.9		(0.4	)	–		92.5		106.8		–		(152.3	)	(45.5	)	115.3
Power Systems		324.2		–		–		324.2		361.2		–		(57.7	)	303.5		350.6
Energy Supply		36.1		–		–		36.1		50.6		–		(29.4	)	21.2		56.7
Southern Water		221.2		–		–		221.2		286.5		–		(8.4	)	278.1		262.2
Telecoms	(iv)	(58.0	)	(2.4	)	–		(60.4	)	(9.5	)	(3.6	)	–		(13.1	)	10.3
Other		2.5		–		–		2.5		14.1		–		(11.2	)	2.9		7.7
United Kingdom total		618.9		(2.8	)	–		616.1		809.7		(3.6	)	(259.0	)	547.1		802.8
United States
PacifiCorp		351.3		(124.8	)	(120.7	)	105.8		151.7		(36.8	)	–		114.9		–
United States total		351.3		(124.8	)	(120.7	)	105.8		151.7		(36.8	)	–		114.9		–
Total		970.2		(127.6	)	(120.7	)	721.9		961.4		(40.4	)	(259.0	)	662.0		802.8
										2001	Depreciation 2000		Impairment 2000			2000		1999
(c) Depreciation by segment										£m		£m		£m		£m		£m
United Kingdom
Generation Wholesale										23.3		17.9		44.5		62.4		29.9
Power Systems										101.1		108.2		25.6		133.8		94.9
Energy Supply										20.7		6.8		21.9		28.7		6.8
Southern Water										71.2		66.1		–		66.1		59.9
Telecoms										36.5		23.5		38.5		62.0		15.3
Other										23.9		21.1		4.9		26.0		17.4
United Kingdom total										276.7		243.6		135.4		379.0		224.2
United States
PacifiCorp										203.6		76.6		–		76.6		–
United States total										203.6		76.6		–		76.6		–
Total										480.3		320.2		135.4		455.6		224.2

(i) The Telecoms segment included external turnover of £25.7 million for the year ended 31 March 2000 and £45.8 million for the year ended 31 March 1999 in respect of the group's mobile telephone business which was disposed of in November 1999.

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

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

(iv) Goodwill amortisation for the Telecoms segment in 1999 was £1.2 million.

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Notes to the Group Profit and Loss Account for the year ended 31 March 2001

2 Operating profit
Operating profit is stated after charging/(crediting):	2001 £m		2000 £m		1999 £m
Depreciation and impairment of tangible fixed assets	480.3		417.1		224.2
Amortisation of goodwill	127.6		40.4		1.2
Release of customer contributions/grants	(15.1	)	(15.6	)	(13.6	)
Research and development	4.2		5.5		5.3
Hire of plant and equipment – operating leases	0.3		0.4		4.6
Hire of other assets – operating leases	54.6		44.7		31.0
Auditors’ remuneration for audit of
– group	1.5		1.1		0.7
– company	–		–		–
Non-audit fees paid to auditors:
Regulatory advice	1.3		1.2		0.9
Advice on systems and consultancy services	5.4		3.9		0.9
Taxation advice	3.1		1.2		–
Due diligence, London Stock Exchange and SEC reporting	1.6		3.8		3.6
Total UK and US non-audit fees paid to auditors	11.4		10.1		5.4
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 (1999 £2.3 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 (1999 £3.1 million) was included within costs of acquisition of PacifiCorp. Operating profit for the years ended 31 March 2001 and 31 March 2000 is also stated after crediting net earnings of £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 £33.8 million and £10.8 million less finance costs of £29.5 million and £9.5 million respectively.

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Notes to the Group Profit and Loss Account for the year ended 31 March 2001

3 Employee information
(a) Employee costs	2001 £m		2000 £m		1999 £m
Wages and salaries	692.6		464.7		329.3
Social security costs	34.5		33.7		25.9
Pension costs	28.4		20.9		18.0
Total employee costs	755.5		519.3		373.2
Less: charged as capital expenditure	(151.2	)	(89.4	)	(71.8	)
Charged to the profit and loss account	604.3		429.9		301.4

(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
	2001	2000	1999	2001	2000	1999
United Kingdom
Generation Wholesale	737	710	913	699	872	1,009
Power Systems	3,181	4,414	4,444	3,241	4,394	4,472
Energy Supply	3,440	2,147	1,749	3,372	2,059	1,721
Southern Water	2,103	2,143	2,262	2,123	2,203	2,352
Telecoms	2,686	2,516	2,383	2,696	2,379	2,410
Other	3,166	4,395	4,281	3,223	4,466	4,211
United Kingdom total	15,313	16,325	16,032	15,354	16,373	16,175
United States
PacifiCorp	6,668	7,789	–	7,053	7,914	–
United States total	6,668	7,789	–	7,053	7,914	–
Total	21,981	24,114	16,032	22,407	24,287	16,175
The year end and average numbers of full-time equivalent staff employed by the group, including executive directors, were:
	At 31 March			Annual average
	2001	2000	1999	2001	2000	1999
United Kingdom	14,209	15,176	15,145	14,174	15,224	15,196
United States	6,612	7,742	–	6,993	7,791	–
Total	20,821	22,918	15,145	21,167	23,015	15,196
(c) Directors’ remuneration Details, for each director, of remuneration, pension entitlements and interests in share options are set out on pages 63 to 66.

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Notes to the Group Profit and Loss Account for the year ended 31 March 2001

4 Exceptional items
	Notes	2001 £m		2000 £m		1999 £m
(a) Recognised in arriving at operating profit
Reorganisation costs	(i),(ii)	(120.7	)	(55.0	)	–
Energy contracts	(iii)	–		(107.1	)	–
Impairment of assets	(iv)	–		(96.9	)	–
		(120.7	)	(259.0	)	–
(b) Recognised after operating profit
Share of joint venture impairment of assets		–		(3.3	)	–
Gain on partial disposal of Thus	(v)	–		787.0		–
Loss on disposal of and withdrawal from other Telecoms operations	(vi)	–		(55.0	)	–
		–		728.7		–
Restructuring of debt portfolio	(vii)	–		(15.9	)	–
Tax on exceptional items		45.9		(56.0	)	–
		45.9		656.8		–
Total exceptional items (net of tax)		(74.8	)	397.8		–

Year ended 31 March 2001
(i)	A charge of £120.7 million relates to the cost of the Transition Plan for PacifiCorp announced on 4 May 2000 and primarily represents severance and related costs.
Year ended 31 March 2000
(ii)	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.
(iii)	Exceptional charges were recorded for the onerous costs of contracted energy and fuel purchases which were not expected to be recoverable.
(iv)	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.
(v)	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.
(vi)	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 assets of £40.5 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.
(vii)	Finance costs 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.

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Notes to the Group Profit and Loss Account for the year ended 31 March 2001

5 Net interest and similar charges
Analysis of net interest and similar charges	2001 £m		2000 £m		1999 £m
Interest on bank loans and overdrafts	38.1		24.6		35.5
Interest on other borrowings	333.7		251.1		144.4
Finance leases	2.2		0.7		–
Total interest payable	374.0		276.4		179.9
Interest receivable	(33.7	)	(9.6	)	(3.8	)
Capitalised interest	(32.2	)	(28.8	)	(14.8	)
Net interest charge	308.1		238.0		161.3
Unwinding of discount on provisions	16.0		5.4		–
Foreign exchange	8.8		–		–
Net interest and similar charges	332.9		243.4		161.3
Interest cover (times)	3.0		4.2		5.0
Interest cover is calculated by dividing profit on ordinary activities before interest (excluding exceptional items and goodwill amortisation) by the sum of the net interest charge (excluding exceptional interest charges) and the unwinding of discount.

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Notes to the Group Profit and Loss Account for the year ended 31 March 2001

6 Tax on profit on ordinary activities
	Before exceptional item 2001 £m		Exceptional item 2001 £m		2001 £m		Before exceptional items 2000 £m	Exceptional items 2000 £m	2000 £m	1999 £m
Current tax:
UK Corporation tax at 30% (2000 30% and 1999 31%)	145.6		–		145.6		135.6	56.0	191.6	141.6
Double taxation relief	(61.2	)	–		(61.2	)	–	–	–	–
UK Corporation tax liability	84.4		–		84.4		135.6	56.0	191.6	141.6
Foreign taxation	5.7		(8.7	)	(3.0	)	26.1	–	26.1	–
Total current tax	90.1		(8.7	)	81.4		161.7	56.0	217.7	141.6
Deferred tax:
Origination and reversal of timing differences	51.0		(37.2	)	13.8		45.2	–	45.2	33.5
Total deferred tax	51.0		(37.2	)	13.8		45.2	–	45.2	33.5
Total tax on profit on ordinary activities	141.1		(45.9	)	95.2		206.9	56.0	262.9	175.1

The rate of current tax charge on profit on ordinary activities before exceptional items and goodwill amortisation varied from the standard rate of corporation tax in the UK due to the following factors:
	Before exceptional item 2001 %		Before exceptional items 2000 %		1999 %
UK corporation tax rate	30.0		30.0		31.0
Permanent differences	(9.8	)	(2.6	)	(1.9	)
Net effect of different rates of tax in overseas businesses	2.3		0.7		–
Advance corporation tax written back	–		–		(2.0	)
Effective tax rate on ordinary activities	22.5		28.1		27.1
Effect of deferred tax	(8.1	)	(6.1	)	(5.2	)
Effective current tax rate on ordinary activities	14.4		22.0		21.9
Financial Reporting Standard (FRS) 19 ‘Deferred tax’ issued on 7 December 2000 requires full provision to be made for deferred tax assets and liabilities, subject to certain exceptions. Previously deferred tax was provided for in respect of timing differences to the extent that it was probable that a liability would crystallise in the foreseeable future. FRS 19 has been applied in preparing the 31 March 2001 Accounts and comparative figures have been restated in the Group Profit and Loss Account, the Balance Sheet and Notes. The effect on the group’s previously reported results and net assets is as follows:
Profit retained			2000 £m		1999 £m
As previously reported			600.9		234.9
Effect of implementing new accounting policy			(57.3	)	(33.5	)
As restated			543.6		201.4
Net assets					2000 £m
As previously reported					6,663.6
Effect of implementing new accounting policy					(800.6	)
As restated					5,863.0
As a result of the change in accounting policy, the profit for the year ended 31 March 2001 has been reduced by £91.7 million. The effect of the change in accounting policy on profit retained for the year ended 31 March 2000 has been to increase the charge for deferred tax and the goodwill amortisation relating to the PacifiCorp acquisition.

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Notes to the Group Profit and Loss Account for the year ended 31 March 2001

7 Earnings per ordinary share
(a) Earnings per ordinary share have been calculated for all years by dividing the profit for the financial year by the weighted average number of ordinary shares in issue during the financial year, based on the following information:
	2001	2000		1999
Profit for the financial year (£ million)	307.5	885.0		469.3
Basic weighted average share capital (number of shares, million)	1,830.3	1,389.6		1,185.2
Diluted weighted average share capital (number of shares, million)	1,837.4	1,399.2		1,197.2
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. (b) The calculation of earnings per ordinary share, on a basis which excludes exceptional items and goodwill amortisation, is based on the following adjusted earnings:
	2001	2000		1999
	£m	£m		£m
Profit for the financial year	307.5	885.0		469.3
Adjusting items – exceptional items (net of attributable taxation)	74.8	(397.8	)	–
– goodwill amortisation	127.6	40.4		1.2
Adjusted earnings	509.9	527.6		470.5
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. As a result of the group’s implementation of FRS 19, earnings per share disclosures have been expanded to show the effect of deferred tax on earnings per share before exceptional items and goodwill amortisation. The deferred tax charge on pre-exceptional profits amounted to £51.0 million for the year ended 31 March 2001, £45.2 million for the year ended 31 March 2000 and £33.5 million for the year ended 31 March 1999.

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Notes to the Group Profit and Loss Account for the year ended 31 March 2001

8 Dividends per ordinary share
	2001 pence per ordinary share	2000 pence per ordinary share	1999 pence per ordinary share	2001 £m	2000 £m	1999 £m
First interim dividend paid	6.51	8.27	7.50	119.1	95.2	89.9
Second interim dividend paid	6.51	8.10	–	119.3	92.1	–
Third interim dividend paid	6.51	2.23	–	119.5	40.7	–
Final dividend	6.51	6.20	15.00	119.4	113.4	178.0
Total dividends	26.04	24.80	22.50	477.3	341.4	267.9

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Group Cash Flow Statement for the year ended 31 March 2001

	Notes	2001 £m		2000 £m		1999 £m
Cash inflow from continuing operating activities	10	1,411.6		1,117.5		944.9
Dividends received from associates and joint ventures		2.1		0.5		0.9
Returns on investments and servicing of finance	9	(373.5	)	(258.4	)	(149.9	)
Ordinary taxation		(152.6	)	(154.3	)	(93.7	)
Free cash flow before windfall tax		887.6		705.3		702.2
Exceptional taxation – windfall tax		–		–		(157.8	)
Free cash flow		887.6		705.3		544.4
Capital expenditure and financial investment	9	(1,081.4	)	(842.3	)	(683.0	)
Cash flow before acquisitions and disposals		(193.8	)	(137.0	)	(138.6	)
Acquisitions and disposals	9	482.9		718.8		(77.4	)
Equity dividends paid		(471.3	)	(406.0	)	(252.8	)
Cash (outflow)/inflow before use of liquid resources and financing		(182.2	)	175.8		(468.8	)
Management of liquid resources	9,13	(11.9	)	(9.8	)	(12.1	)
Financing
– Issue of ordinary share capital (net of costs)	9	6.6		(29.2	)	3.2
– Issue of ordinary share capital by a subsidiary (net of costs)		–		310.0		–
– Share buy-back (including costs)		–		(302.0	)	–
– Increase/(decrease) in debt	9,13	189.5		(100.0	)	451.0
		196.1		(121.2	)	454.2
Increase/(decrease) in cash in year	13	2.0		44.8		(26.7	)
Free cash flow represents cash flow from continuing operating activities after adjusting for dividends received from associates and joint ventures, returns on investments and servicing of finance and taxation.
The Accounting Policies and Definitions , together with Notes 1 to 40 form part of these Accounts.

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Reconciliation of Net Cash Flow to Movement in Net Debt for the year ended 31 March 2001

	Note	2001 £m		2000 £m		1999 £m
Increase/(decrease) in cash in year		2.0		44.8		(26.7	)
Cash (inflow)/outflow from (increase)/decrease in debt		(189.5	)	100.0		(451.0	)
Cash outflow from movement in liquid resources		11.9		9.8		12.1
Change in net debt resulting from cash flows		(175.6	)	154.6		(465.6	)
Net debt acquired		–		(2,565.6	)	(2.7	)
Net debt disposed		–		8.5		–
Exchange		(264.7	)	(17.3	)	–
Other non-cash movements		(3.3	)	(0.5	)	(0.3	)
Movement in net debt in year		(443.6	)	(2,420.3	)	(468.6	)
Net debt at end of previous year		(4,841.5	)	(2,421.2	)	(1,952.6	)
Net debt at end of year	13	(5,285.1	)	(4,841.5	)	(2,421.2	)
The Accounting Policies and Definitions , together with Notes 1 to 40 form part of these Accounts.

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Notes to the Group Cash Flow Statement for the year ended 31 March 2001

9 Analysis of cash flows
	2001 £m		2000 £m		1999 £m
(a) Returns on investments and servicing of finance
Interest received	32.7		9.7		3.5
Interest paid	(395.8	)	(265.7	)	(153.4	)
Dividends paid to minority interests	(10.4	)	(2.4	)	–
Net cash outflow for returns on investments and servicing of finance	(373.5	)	(258.4	)	(149.9	)
(b) Capital expenditure and financial investment
Purchase of tangible fixed assets	(1,143.6	)	(917.7	)	(745.1	)
Deferred income received	97.3		55.5		47.8
Sale of tangible fixed assets	26.4		26.5		20.4
Purchase of fixed asset investments	(61.5	)	(6.6	)	(6.1	)
Net cash outflow for capital expenditure and financial investment	(1,081.4	)	(842.3	)	(683.0	)
(c) Acquisitions and disposals
Purchase of businesses and subsidiary undertakings	(230.2	)	2.1		(77.4	)
Sale of businesses and subsidiary undertakings	713.1		(3.7	)	–
Partial disposal of Thus	–		720.4		–
Net cash inflow/(outflow) from acquisitions and disposals	482.9		718.8		(77.4	)
(d) Management of liquid resources*
Cash outflow in relation to short-term deposits and other short-term investments	(11.9	)	(9.8	)	(12.1	)
Net cash outflow for management of liquid resources	(11.9	)	(9.8	)	(12.1	)
(e) Financing
Issue of ordinary share capital	6.6		3.8		3.2
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	)	–
	6.6		(21.2	)	3.2
Debt due within one year:
– net drawdown/(repayment) of uncommitted facilities	6.6		(75.0	)	(39.1	)
– net commercial paper issued/(redeemed)	6.1		(285.8	)	(174.9	)
– medium-term notes/private placements	(58.9	)	(3.3	)	(62.5	)
– issue/(redemption) of loan notes	0.4		(8.0	)	(1.1	)
– European Investment Bank loans	(4.6	)	0.8		(10.0	)
– mortgages	(96.4	)	4.2		–
– non recourse notes	(147.2	)	–		–
– other	0.5		–		–
Debt due after one year:
– medium-term notes/private placements	594.2		178.1		197.5
– European Investment Bank loans	42.8		86.2		51.2
– 6.750% euro-sterling bond issue	–		–		247.0
– 5.250% deutschmark bond issue	–		–		245.5
– 11.457% sterling bond issue	–		(142.0	)	–
– 6.625% euro-sterling bond issue	–		197.9		–
– mortgages	(25.8	)	(53.1	)	–
– secured pollution control revenue bonds	0.2		–		–
– unsecured pollution control revenue bonds	1.9		–		–
– junior debentures	(117.0	)	–		–
– non recourse notes	(21.2	)	–		–
– other	8.0		–		–
Capital element of finance lease rental payments	(0.1	)	–		(2.6	)
Increase/(decrease) in debt	189.5		(100.0	)	451.0
Net cash inflow/(outflow) from financing	196.1		(121.2	)	454.2
* Liquid resources include term deposits of less than one year, commercial paper and other short-term investments.

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Notes to the Group Cash Flow Statement for the year ended 31 March 2001

10 Reconciliation of operating profit to net cash inflow from continuing operating activities
	2001 £m		2000 £m		1999 £m
Operating profit	721.9		662.0		802.8
Depreciation and amortisation	607.9		457.6		225.4
Profit on sale of tangible fixed assets and disposal of businesses	(19.9	)	(19.8	)	(18.6	)
Release of deferred income	(15.1	)	(15.6	)	(13.6	)
Movements in provisions for liabilities and charges	57.5		103.1		(7.3	)
(Increase)/decrease in stocks	(13.3	)	20.1		18.4
Increase in debtors	(137.2	)	(32.1	)	(68.7	)
Increase/(decrease) in creditors	209.8		(57.8	)	6.5
Net cash inflow from continuing operating activities	1,411.6		1,117.5		944.9

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Notes to the Group Cash Flow Statement for the year ended 31 March 2001

11 Effect of acquisitions and disposals on cash flows
	Acquisition 2000 £m		Acquisitions 1999 £m
Cash flow from operating activities	242.4		21.1
Returns on investments and servicing of finance	(40.6	)	0.3
Taxation	7.6		(0.1	)
Capital expenditure and financial investment	(103.1	)	(10.6	)
Equity dividends paid	(9.8	)	–
Management of liquid resources	–		(9.2	)
Financing	(71.0	)	(1.6	)
Increase/(decrease) in cash	25.5		(0.1	)
The effect of acquisitions and disposals on cash flows during 2001 is 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. The analysis of cash flows of the acquisitions in 1999 relates to the post-acquisition cash flows of Demon Internet Limited and Watermark Games Limited. There were no disposals in 1999.

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Notes to the Group Cash Flow Statement for the year ended 31 March 2001

12 Analysis of cash flows in respect of acquisitions and disposals
	Acquisition 2001 £m		Disposals 2001 £m		Acquisition 2000 £m		Disposal 2000 £m		Acquisitions 1999 £m
Cash consideration including expenses	(227.7	)	716.5		(28.4	)	–		(69.7	)
Cash at bank and in hand acquired/(disposed)	–		–		41.4		(3.7	)	1.4
Pre-completion dividend to former PacifiCorp shareholders	–		–		(9.8	)	–		–
Deferred consideration in respect of prior year acquisitions	(2.5	)	–		(1.1	)	–		(9.1	)
Expenses paid in respect of prior year disposals	–		(3.4	)	–		–		–
	(230.2	)	713.1		2.1		(3.7	)	(77.4	)
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

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Notes to the Group Cash Flow Statement for the year ended 31 March 2001

13 Analysis of net debt
	At				Acquisition		Disposal			Other		At
	1 April				(excl. cash &		(excl. cash &			non–cash		31 March
1999 – 00	1999		Cash flow		overdrafts)		overdrafts)	Exchange		changes		2000
	£m		£m		£m		£m	£m		£m		£m
Cash at bank	38.1		68.6		–		–	–		–		106.7
Overdrafts	(15.3	)	(23.8	)	–		–	–		–		(39.1	)
			44.8
Debt due after 1 year	(1,684.5	)	(267.1	)	(2,349.6	)	–	(15.9	)	(0.5	)	(4,317.6	)
Debt due within 1 year	(828.3	)	367.1		(199.1	)	8.5	(1.2	)	–		(653.0	)
Finance leases	–		–		(16.9	)	–	(0.2	)	–		(17.1	)
			100.0
Other deposits	68.8		9.8		–		–	–		–		78.6
Total	(2,421.2	)	154.6		(2,565.6	)	8.5	(17.3	)	(0.5	)	(4,841.5	)

‘Other non–cash changes’ to net debt represents amortisation of finance costs of £0.5 million.
	At						Other		At
2000 – 01	1 April						non–cash		31 March
	2000 £m		Cash flow £m		Exchange £m		changes £m		2001 £m
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.

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Group Balance Sheet as at 31 March 2001

	Notes	2001 £m		2000 £m
Fixed assets
Intangible assets	16	2,840.8		2,188.4
Tangible assets	17	11,920.8		10,683.3
Investments
– Investments in joint ventures:
Share of gross assets		118.4		95.9
Share of gross liabilities		(74.6	)	(76.3	)
		43.8		19.6
– Investments in associates		5.0		5.4
– Other investments		247.5		207.6
	18	296.3		232.6
		15,057.9		13,104.3
Current assets
Businesses held for disposal		–		563.2
Stocks	19	215.1		202.3
Debtors	20
– Gross debtors		1,758.2		1,732.9
– Less non–recourse financing		(285.7	)	(271.9	)
		1,472.5		1,461.0
Short–term bank and other deposits		230.2		185.3
		1,917.8		2,411.8
Creditors: amounts falling due within one year
Loans and other borrowings	21	(627.9	)	(692.1	)
Other creditors	22	(2,375.9	)	(2,066.0	)
		(3,003.8	)	(2,758.1	)
Net current liabilities		(1,086.0	)	(346.3	)
Total assets less current liabilities		13,971.9		12,758.0
Creditors: amounts falling due after more than one year
Loans and other borrowings	21	(4,887.4	)	(4,334.7	)
Provisions for liabilities and charges
– Deferred tax	24	(1,625.3	)	(1,612.1	)
– Other provisions	23	(778.7	)	(521.4	)
		(2,404.0	)	(2,133.5	)
Deferred income	25	(501.5	)	(426.8	)
Net assets	14	6,179.0		5,863.0
Called up share capital	26, 27	924.5		923.8
Share premium	27	3,739.7		3,733.8
Revaluation reserve	27	217.1		220.5
Capital redemption reserve	27	18.3		18.3
Merger reserve	27	406.4		406.4
Profit and loss account	27	587.2		260.5
Equity shareholders’ funds	27	5,893.2		5,563.3
Minority interests (including non–equity)	28	285.8		299.7
Capital employed		6,179.0		5,863.0
Net asset value per ordinary share	15	318.7	p	301.1	p
Approved by the Board on 3 May 2001 and signed on its behalf by
Charles Miller Smith Chairman	David Nish Finance Director
The Accounting Policies and Definitions , together with Notes 1 to 40 form part of these Accounts.

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Notes to the Group Balance Sheet as at 31 March 2001

14 Segmental information
(a) Net assets by segment	Notes	2001 £m		2000 £m
United Kingdom
Generation Wholesale		459.8		201.0
Power Systems		1,871.3		1,955.2
Energy Supply		196.2		200.9
Southern Water		1,831.4		1,618.0
Telecoms		308.1		377.7
Other	(i)	87.3		56.8
United Kingdom total		4,754.1		4,409.6
United States
PacifiCorp		7,562.0		7,159.2
United States total		7,562.0		7,159.2
Unallocated net liabilities	(ii)	(6,137.1	)	(5,705.8	)
Total		6,179.0		5,863.0
(b) Capital expenditure by segment	(iii)	2001 £m		2000 £m
United Kingdom
Generation Wholesale		120.9		32.0
Power Systems		217.0		216.5
Energy Supply		37.2		41.4
Southern Water		319.5		362.6
Telecoms		158.9		164.8
Other		9.8		27.8
United Kingdom total		863.3		845.1
United States
PacifiCorp		328.8		97.3
United States total		328.8		97.3
Total		1,192.1		942.4
(c) Total assets by segment		2001 £m		2000 £m
United Kingdom
Generation Wholesale		922.5		442.4
Power Systems		2,489.0		2,496.3
Energy Supply		534.5		487.5
Southern Water		2,824.5		2,575.4
Telecoms		599.5		450.0
Other		138.4		73.4
United Kingdom total		7,508.4		6,525.0
United States
PacifiCorp		9,467.3		8,991.1
United States total		9,467.3		8,991.1
Total		16,975.7		15,516.1

(i)	The net liabilities of the Appliance Retailing business, included within the Other business segment, excluding short-term bank and other deposits of £55.4 million (2000 £48.8 million), are £0.8 million (2000 net assets £9.1 million).
(ii)	Unallocated net liabilities include net debt, dividends payable, tax liabilities, investments and businesses held for disposal.
(iii)	Capital expenditure by business segment is stated gross of capital grants and customer contributions. Capital expenditure net of contributions amounted to £1,095.6 million (2000 £887.3 million).

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Notes to the Group Balance Sheet as at 31 March 2001

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 years (after adjusting for the effect of shares held in trust for the group’s Sharesave Schemes and Employee Share Ownership Plan):
	2001	2000
Net assets (as adjusted) (£ million)	5,841.9	5,503.8
Number of ordinary shares in issue at year end (as adjusted) (number of shares, million)	1,833.0	1,827.9

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Notes to the Group Balance Sheet as at 31 March 2001

16 Intangible fixed assets
Year ended 31 March 2000	Note	Goodwill £m
Cost:
At 1 April 1999		72.5
Acquisition – as restated for FRS 19	30	2,177.4
Disposals		(36.4	)
Exchange		15.0
At 31 March 2000 – as restated		2,228.5
Amortisation:
At 1 April 1999		1.2
Amortisation for the year – as restated for FRS 19		40.4
Disposals		(1.8	)
Exchange		0.3
At 31 March 2000 – as restated		40.1
Net book value:
At 31 March 2000 – as restated		2,188.4
At 31 March 1999		71.3
Year ended 31 March 2001	Notes	Goodwill £m
Cost:
At 1 April 2000		2,228.5
Acquisition	29	97.1
Revision to provisional fair values	30	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
At 31 March 1999		71.3
Goodwill capitalised is being amortised over its estimated useful economic life, which is a range of between 15 to 20 years.

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Notes to the Group Balance Sheet as at 31 March 2001

17 Tangible fixed assets
Year ended 31 March 2000	Land and buildings £m		Water infrastructure assets £m		Plant and machinery £m		Vehicles and equipment £m		Total £m
Cost or valuation:
At 1 April 1999	940.7		991.4		4,032.1		658.7		6,622.9
Additions	102.7		109.1		532.9		197.7		942.4
Acquisition	180.5		–		4,268.7		433.4		4,882.6
Grants and contributions	–		(6.3	)	–		–		(6.3	)
Disposals	(7.4	)	(0.5	)	(25.2	)	(12.3	)	(45.4	)
Exchange	1.3		–		30.0		3.2		34.5
At 31 March 2000	1,217.8		1,093.7		8,838.5		1,280.7		12,430.7
Depreciation:
At 1 April 1999	170.9		48.4		967.0		141.5		1,327.8
Charge for the year	65.5		20.2		133.7		100.8		320.2
Impairment	2.4		–		59.9		73.1		135.4
Disposals	(1.8	)	(0.5	)	(25.2	)	(9.2	)	(36.7	)
Exchange	–		–		0.5		0.2		0.7
At 31 March 2000	237.0		68.1		1,135.9		306.4		1,747.4
Net book value:
At 31 March 2000	980.8		1,025.6		7,702.6		974.3		10,683.3
At 31 March 1999	769.8		943.0		3,065.1		517.2		5,295.1

Year ended 31 March 2001	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
Historical cost analysis							2001 £m		2000 £m
Cost							13,941.9		12,278.7
Depreciation based on cost							(2,238.2	)	(1,815.9	)
Net book value based on cost							11,703.7		10,462.8
Included in the cost or valuation of tangible fixed assets above are:					Notes		2001 £m		2000 £m
Major assets in the course of construction							900.3		706.4
Grants and contributions in respect of water infrastructure assets							(33.0	)	(24.3	)
Capitalised interest					(ii)		94.5		61.6
Assets not subject to depreciation					(iii)		185.1		136.0

(i)	The Manweb distribution and Southern Water operational assets were revalued by the directors on 30 September 1997. The valuations have 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 2001 was £2,198.1 million (2000 £2,253.1 million).
(ii)	Interest on the funding attributable to major capital projects was capitalised during the year at a rate of 8% (2000 8%) in the United Kingdom and 7% (2000 7%) in the United States.
(iii)	Assets not subject to depreciation are land. Land and buildings held by the group are predominantly freehold.
(iv)	The historical cost of fully depreciated tangible fixed assets still in use was £224.6 million (2000 £256.3 million).
(v)	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 £455.5 million (2000 £333.1 million). The depreciation charge was £52.5 million (2000 £78.3 million including impairment, 1999 £10.9 million).
(vi)	The net book value of land and buildings held under finance leases at 31 March 2001 was £28.0 million (2000 £17.0 million). The charge for depreciation against these assets during the year was £0.9 million (2000 £nil).
(vii)	Assets which were impaired in 2000 were valued on the basis of their estimated recoverable amounts.
The impairment charge in the year ended 31 March 2000 of £135.4 million has been 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 from withdrawal from operations, £38.5 million.

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Notes to the Group Balance Sheet as at 31 March 2001 - continued

18 Fixed asset investments
			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 1999			3.3		21.1		5.9		41.6		1.8		73.7
Additions			–		1.0		–		36.9		12.6		50.5
Acquisitions			–		–		–		0.4		123.4		123.8
Share of retained (loss)/profit			(3.0	)	–		0.1		–		–		(2.9	)
Disposals and other			–		(2.8	)	(0.6	)	(8.5	)	(1.4	)	(13.3	)
Exchange			–		–		–		–		0.8		0.8
At 31 March 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
The principal subsidiary undertakings, joint ventures and associated undertakings are listed here . Details of listed investments held are given below:
													£m
Balance Sheet value at 31 March 2001													119.9
Market value at 31 March 2001													128.4
(a) Shares in the company held under trust during the year are as follows:
	Notes	Dividends waived	Shares held at 1 April 1999 (000s)		Shares acquired during year (000s)		Shares transferred during year (000s)		Shares held at 31 March 2000 (000s)		Nominal value at 31 March 2000 £m		Market value at 31 March 2000 £m
Long Term Incentive Plan	(i)	no	1,877		564		–		2,441		1.2		12.4
ScottishPower Sharesave Schemes	(ii)	yes	12,790		10,253		(3,402	)	19,641		9.8		99.7
PacifiCorp Stock Incentive Plan	(iii)	no	–		108	*	(50	)	58		–		0.3
			14,667		10,925		(3,452	)	22,140		11.0		112.4
	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	(iii)	no	58		131		(75	)	114		0.1		1.0
Employee Share Ownership Plan	(iv)	no	–		747		–		747		0.4		3.5
			22,140		1,386		(4,713	)	18,813		9.5		88.5

*	For the PacifiCorp Stock Incentive Plan this represents the balance of shares at 29 November 1999.
(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 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)	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. The figures relating to the PacifiCorp Stock Incentive Plan for the year ended 31 March 2000 relate to the period between the date of acquisition and 31 March 2000 and represent the unvested and unforfeited shares of restricted stock held.
(Iv)	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.

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Notes to the Group Balance Sheet as at 31 March 2001

19 Stocks
	2001 £m	2000 £m
Raw materials and consumables	103.7	98.5
Fuel stocks	53.1	47.0
Work in progress	8.2	11.6
Finished goods and goods for resale	50.1	45.2
	215.1	202.3

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Notes to the Group Balance Sheet as at 31 March 2001

20 Debtors
	Notes	2001 £m		2000 £m
(a) Amounts falling due within one year:
Trade debtors	(i)	620.0		482.2
Amounts receivable under finance leases	(ii)	42.6		43.7
Less non-recourse financing		(22.4	)	(17.2	)
		20.2		26.5
Prepayments and accrued income		428.1		391.6
Other debtors		55.8		154.5
		1,124.1		1,054.8
(b) Amounts falling due after more than one year:
Amounts receivable under finance leases	(ii)	461.2		435.5
Less non-recourse financing		(263.3	)	(254.7	)
		197.9		180.8
Other debtors		150.5		225.4
		1,472.5		1,461.0

(i)

Trade debtors are stated net of provisions for doubtful debts of £74.7 million (2000 £69.6 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. Amounts receivable under finance leases at 31 March 2001 of £461.2 million (2000 £435.5 million) are due as follows: between 1-2 years, £120.9 million (2000 £36.7 million); between 2-3 years, £49.8 million (2000 £98.0 million); between 3-4 years, £37.1 million (2000 £43.0 million); between 4-5 years, £28.9 million (2000 £44.5 million) and after 5 years, £224.5 million (2000 £213.3 million). Total amounts receivable under finance leases during the year were £32.3 million (2000 £32.0 million).

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Notes to the Group Balance Sheet as at 31 March 2001

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 . The analyses of financial instruments in this Note do not include short-term debtors and creditors as permitted by FRS 13.
			Weighted average interest rate
(a) Analysis by instrument	Notes	2001			2000		2001 £m	2000 £m
Unsecured debt of UK businesses
Bank overdraft		–			–		23.6	23.7
Uncommitted bank loan		6.0		%	5.3	%	96.0	89.3
Commercial paper	(i)	6.0		%	5.4	%	203.8	289.5
Medium-term notes/private placements	(ii)	6.5		%	5.9	%	1,151.3	613.2
Loan notes	(iii)	6.2		%	5.4	%	9.1	8.7
European Investment Bank loans	(iv)	7.2		%	7.9	%	342.8	304.6
5.875% euro-US dollar bond 2003		6.9		%	6.9	%	183.4	183.2
Variable coupon bond 2008		6.9		%	6.8	%	99.7	99.7
5.250% deutschmark bond 2008		6.8		%	6.8	%	245.7	245.6
6.625% euro-sterling bond 2010		6.6		%	6.7	%	198.1	197.9
8.375% euro-sterling bond 2017		8.4		%	8.4	%	197.1	197.1
6.750% euro-sterling bond 2023		6.8		%	6.8	%	247.1	247.0
Unsecured debt of US businesses
Bank overdraft		–			–		28.9	15.4
Commercial paper	(i)	6.2		%	6.2	%	169.1	68.3
PacifiCorp Group Holdings Senior Notes		7.3		%	6.9	%	–	156.1
Junior subordinated debentures	(v)	8.4		%	8.8	%	–	105.9
Preferred securities	(vi)	8.6		%	8.6	%	232.1	206.9
Pollution control revenue bonds	(ix)	3.5		%	3.8	%	315.2	279.1
Finance leases	(vii)	11.9		%	11.9	%	19.1	17.1
Unsecured debt							3,762.1	3,348.3
Secured debt of US businesses
First mortgage and collateral trust bonds	(viii)	7.6		%	7.6	%	1,486.4	1,443.3
Pollution control revenue bonds	(ix)	3.7		%	4.2	%	198.8	177.2
Other		7.2		%	7.6	%	68.0	58.0
Secured debt							1,753.2	1,678.5
							5,515.3	5,026.8

(i)	Commercial paper Scottish Power UK plc has an established US$2.0 billion (2000 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 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$4.0 billion euro-medium-term note programme. Paper is issued in a range of currencies and swapped back into sterling. As at 31 March 2001, maturities range from 1 to 39 years.
(iii)	Loan notes All loan notes are redeemable at the holders discretion. Ultimate maturity dates range from 2001 to 2006.
(iv)	European Investment Bank loans These loans incorporate agreements with various interest rates and maturity dates. The maturity dates of these arrangements range from 2006 to 2011.
(v)	Junior subordinated debentures The junior subordinated debentures were subordinated to PacifiCorp's first mortgage and collateral trust bonds, pollution control revenue bonds, commercial paper, bank debt and any other future indebtedness.
(vi)	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.
(vii)	Finance leases These are facility leases that are accounted for as capital leases, maturity dates range from 2013 to 2021.
(viii)	First mortgage and collateral trust bonds First mortgage and collateral trust 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$11.4 billion of the eligible assets (based on original costs) of PacifiCorp is subject to the lien of the mortgage.
(ix)	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 trust bonds as collateral for repayment.

	At 31 March 2001			At 31 March 2000
(b) Fair value of financial instruments	Book amount £m	Fair value £m		Book amount £m	Fair value £m
Short-term debt and current portion of long-term debt	627.9	627.9		692.1	692.1
Long-term debt	4,887.4	5,101.3		4,334.7	4,351.3
Total debt	5,515.3	5,729.2		5,026.8	5,043.4
Interest rate swaps	–	54.8		–	18.9
Interest rate swaptions	4.0	1.9		4.2	1.4
Forward rate agreements	–	0.1		–	–
Interest rate caps	–	–		–	(0.9	)
Cross currency interest rate swaps	–	(25.5	)	–	11.5
Forward contracts	8.1	16.0		–	1.3
Total financial instruments	5,527.4	5,776.5		5,031.0	5,075.6

The assumptions used to estimate fair values of debt and other financial instruments are summarised below:
(i)	For cash, short-term deposits and 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 European Investment Bank 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.

 

(c) Maturity analysis	2001 £m	2000 £m
Repayments fall due as follows:
Within one year, or on demand	627.9	692.1
After more than one year	4,887.4	4,334.7
	5,515.3	5,026.8
Repayments due after more than one year are analysed as follows:
Between one and two years	434.9	194.4
Between two and three years	213.7	363.9
Between three and four years	259.2	148.7
Between four and five years	349.2	242.0
More than five years	3,630.4	3,385.7
	4,887.4	4,334.7

Included in the 31 March 2001 ‘More than five years’ figure above is £19.1 million for finance leases (2000 £17.1 million).
Liabilities:	2002 £m	2003 £m	2004 £m	2005 £m	2006 £m	Thereafter £m	Total £m	Fair Value £m
Fixed rate (GBP)	14.4	15.5	74.7	68.1	18.6	1,102.3	1,293.6	1,357.8
Average interest rate (GBP)	9.6%	9.6%	7.1%	7.4%	9.6%	6.7%	6.9%
Fixed rate (USD) – UK group	–	183.4	–	–	–	51.4	234.8	277.8
Average interest rate (USD) – UK group	–	5.9%	–	–	–	4.6%	5.6%
Fixed rate (USD) – US group	28.2	97.5	95.3	161.7	176.8	1,242.4	1,801.9	1,934.3
Average interest rate (USD) – US group	6.9%	7.1%	7.3%	7.3%	7.4%	8.0%	7.8%
Fixed rate (CHF)	–	–	4.1	–	–	–	4.1	4.0
Average interest rate (CHF)	–	–	2.5%	–	–	–	2.5%
Fixed rate (CZK)	–	–	–	–	34.2	–	34.2	36.9
Average interest rate (CZK)	–	–	–	–	6.9%	–	6.9%
Fixed rate (EUR)	33.0	–	7.0	14.6	–	282.5	337.1	311.4
Average interest rate (EUR)	4.6%	–	4.9%	4.8%	–	5.2%	5.1%
Fixed rate (JPY)	17.0	–	–	–	20.4	29.6	67.0	71.4
Average interest rate (JPY)	0.5%	–	–	–	2.2%	2.1%	1.7%
Fixed rate (SEK)	–	–	–	9.8	–	–	9.8	9.1
Average interest rate (SEK)	–	–	–	5.4%	–	–	5.4%
Index-linked (GBP)	–	–	–	–	–	183.7	183.7	164.8
Average interest rate (GBP)	–	–	–	–	–	3.49xRPI	3.49xRPI
Variable rate (GBP)	239.3	23.0	16.0	5.0	–	186.7	470.0	469.9
Average interest rate (GBP)	1m LIBOR	3m LIBOR	3m LIBOR	3m LIBOR	–	6m LIBOR	3m LIBOR
Variable rate (USD) – UK group	89.4	93.8	16.6	–	66.3	21.2	287.3	304.1
Average interest rate (USD) – UK group	3m LIBOR	3m LIBOR	6m LIBOR	–	3m LIBOR	3m LIBOR	3m LIBOR
Variable rate (USD) – US group	198.0	–	–	–	11.0	447.7	656.7	655.0
Average interest rate (USD) – US group	1m LIBOR	–	–	–	BMA	BMA	BMA
Variable rate (USD) – US group	–	–	–	–	–	59.0	59.0	59.0
Average interest rate (USD) – US group	–	–	–	–	–	MCBY	MCBY
Variable rate (CHF)	–	5.0	–	–	–	–	5.0	4.1
Average interest rate (CHF)	–	3m LIBOR	–	–	–	–	3m LIBOR
Variable rate (EUR)	8.6	16.7	–	–	–	18.7	44.0	43.6
Average interest rate (EUR)	3m LIBOR	3m LIBOR	–	–	–	5m LIBOR	4m LIBOR
Variable rate (JPY)	–	–	–	–	21.9	5.2	27.1	26.0
Average interest rate (JPY)	–	–	–	–	6m LIBOR	6m LIBOR	6m LIBOR
							5,515.3	5,729.2
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, SEK – Swedish Krona, DKK – Danish Krone, AUD – Australian Dollars, RPI – UK Retail Price Index change since issue. 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. Reference to ‘m’ in ‘m LIBOR’ represents months.

	At 31 March 2001			At 31 March 2000
(d) Interest rate analysis	UK £m	US £m	Total £m	UK £m	US £m	Total £m
Fixed rate borrowings	2,090.1	1,801.9	3,892.0	1,925.4	1,982.6	3,908.0
Capped rate borrowings	150.0	–	150.0	150.0	–	150.0
Floating rate borrowings	757.6	715.7	1,473.3	424.1	544.7	968.8
	2,997.7	2,517.6	5,515.3	2,499.5	2,527.3	5,026.8

	Weighted average interest rate at which borrowings are fixed/capped					Weighted average period for which interest rate is fixed/capped
	At 31 March 2001		At 31 March 2000		At 31 March 2001			At 31 March 2000
	UK %	US %	UK %	US %	UK Years		US Years	UK Years	US Years
Fixed rate borrowings	7.1	7.8	7.3	7.7	10		13	10	13
Capped rate borrowings	7.0	–	7.0	–	1		–	2	–
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 2001 were as follows: UK operations 6.0%, US operations 5.7% (2000 5.8% and 6.2% respectively). Based on the floating rate net debt of £1,473.3 million at 31 March 2001 (2000 £968.8 million), a 100 basis point change in interest rates would result in a £14.7 million change in profit before tax for the year (2000 £9.7 million change).

	At 31 March 2001			At 31 March 2000
(e) Financial assets	UK £m	US £m	Total £m	UK £m	US £m	Total £m
Fixed rate financial assets	11.4	330.2	341.6	7.7	204.6	212.3
Floating rate financial assets	121.1	100.2	221.3	98.1	82.2	180.3
	132.5	430.4	562.9	105.8	286.8	392.6
Included within US fixed rate financial assets at 31 March 2001 are amounts receivable under finance leases of £501.3 million (2000 £476.5 million) less non–recourse finance of £285.7 million (2000 £271.9 million) and amounts relating to a finance note of £114.6 million receivable over the period to June 2018 with the option for early settlement. The floating rate financial assets of the group’s UK and US operations are principally cash deposits.

	Weighted average interest rate at which financial assets are fixed				Weighted average period for which interest is fixed
	At 31 March 2001		At 31 March 2000		At 31 March 2001		At 31 March 2000
	UK %	US %	UK %	US %	UK Years	US Years	UK Years	US Years
Fixed rate financial assets	6.5	10.8	7.0	9.7	4	5	4	9
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 2001 were as follows: UK operations 6.1%, US operations 5.2% (2000 6.1% and 5.8% 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 2001 in respect of which all conditions precedent have been met. Of the facilities shown £1,000 million relates to operations in the UK. The remaining £351.7 million relates to operations in the US. During the financial year Scottish Power UK plc cancelled £1,000 million of its £2,000 million revolving credit facility that was outstanding, undrawn as at 31 March 2000.

	Floating rate 2001 £m	Total 2001 £m	Total 2000 £m
Expiring within one year	1,351.7	1,351.7	188.1
Expiring between one and two years	–	–	2,438.9
Commitment fees on the above facilities were as follows: Scottish Power UK plc group £2.6 million (2000 £4.7 million); PacifiCorp group £0.5 million (£0.3 million for the period 29 November 1999 to 31 March 2000).

(g) Maturity analysis of derivatives	2002 £m	2003 £m	2004 £m	2005 £m	2006 £m	Thereafter £m	Total £m	Fair Value £m
Interest rate swaps
Variable to fixed (GBP)	325.0	25.0	50.0	–	–	425.0	825.0	55.7
Average pay rate	6.9%	8.1%	7.7%	–	–	7.3%	7.2%
Average receive rate	4m LIBOR	6m LIBOR	3m LIBOR	–	–	3m LIBOR	3m LIBOR
Fixed to index-linked (GBP)	–	–	–	–	–	100.0	100.0	4.0
Average pay rate	–	–	–	–	–	3.35 x RPI	3.35 x RPI
Average receive rate	–	–	–	–	–	6.2%	6.2%
Fixed to variable (GBP)	50.0	–	–	50.0	–	32.0	132.0	(4.1	)
Average pay rate	3m LIBOR	–	–	6m LIBOR	–	6m LIBOR	5m LIBOR
Average receive rate	5.5%	–	–	6.6%	–	6.6%	6.2%
Variable to variable (GBP)	–	–	–	5.0	–	30.0	35.0	(0.8	)
Average pay rate	–	–	–	6m LIBOR	–	6m LIBOR	6m LIBOR
Average receive rate	–	–	–	3m LIBOR	–	12m LIBOR	11m LIBOR
Interest rate swaptions
Notional amount (GBP)	–	–	–	–	–	100.0	100.0	1.9
Average pay rate	–	–	–	–	–	4.3%	4.3%
Average receive rate	–	–	–	–	–	6m LIBOR	6m LIBOR
Forward rate agreements
Notional amount (GBP)	100.0	–	–	–	–	–	100.0	0.1
Average pay rate	5.3%	–	–	–	–	–	5.3%
Average receive rate	3m LIBOR	–	–	–	–	–	3m LIBOR
Interest rate caps
Notional amount (GBP)	100.0	–	50.0	–	–	–	150.0	–
Strike price	7.0%	–	7.0%	–	–	–	7.0%
Cross currency interest rate swaps
Receive fixed USD pay fixed GBP	–	183.7	–	–	–	–	183.7	(25.8	)
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	(10.8	)
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	(4.2	)
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	(14.6	)
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 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	1.0
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	(2.4	)
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	30.6
Average pay rate (GBP)	–	–	–	–	–	6.7%	6.7%
Average receive rate (EUR)	–	–	–	–	–	5.3%	5.3%
Receive fixed EUR pay variable GBP	33.0	–	7.0	14.6	–	36.8	91.4	5.6
Average pay rate (GBP)	6m LIBOR	–	6m LIBOR	6m LIBOR	–	6m LIBOR	6m LIBOR
Average receive rate (EUR)	4.6%	–	4.9%	4.8%	–	5.0%	4.8%
Receive variable EUR pay variable GBP	8.6	16.7	–	–	–	18.7	44.0	1.3
Average pay rate (GBP)	3m LIBOR	3m LIBOR	–	–	–	6m LIBOR	4m LIBOR
Average receive rate (EUR)	3m LIBOR	3m LIBOR	–	–	–	5m LIBOR	4m LIBOR
Receive fixed JPY pay variable GBP	17.0	–	–	–	20.4	28.1	65.5	(8.3	)
Average pay rate (GBP)	6m LIBOR	–	–	–	6m LIBOR	6m LIBOR	6m LIBOR
Average receive rate (JPY)	0.5%	–	–	–	2.2%	2.1%	1.7%
Receive variable JPY pay variable GBP	–	–	–	–	21.9	5.2	27.1	1.3
Average pay rate (GBP)	–	–	–	–	6m LIBOR	6m LIBOR	6m LIBOR
Average receive rate (JPY)	–	–	–	–	6m LIBOR	6m LIBOR	6m LIBOR
Receive fixed SEK pay variable GBP	–	–	–	9.8	–	–	9.8	0.7
Average pay rate (GBP)	–	–	–	6m LIBOR	–	–	6m LIBOR
Average receive rate (SEK)	–	–	–	5.4%	–	–	5.4%
Forward contracts
Buy GBP, sell USD	301.5	101.2	55.8	–	–	–	458.5	16.8
Buy USD, sell GBP	29.4	–	–	–	–	–	29.4	(1.2	)
Buy DKK, sell GBP	6.7	–	–	–	–	–	6.7	–
Buy SEK, sell GBP	4.6	–	–	–	–	–	4.6	0.3
Buy GBP, sell SEK	1.7	–	–	–	–	–	1.7	–
Buy AUD, sell GBP	8.0	–	–	–	–	–	8.0	0.1
							2,911.8	47.3
The abbreviations contained in the table are defined in Note 21(c).

(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:
	Notes	Gains £m		Losses £m		Total net gains/losses £m
Unrecognised gains and (losses) on hedges at 1 April 1999		10.7		(91.7	)	(81.0	)
Transfer from gains to losses	(i)	(4.6	)	4.6		–
Transfer from losses to gains	(i)	(5.3	)	5.3		–
Losses arising in previous years that were recognised in 1999-00		4.8		40.9		45.7
Gains and (losses) arising before 1 April 1999 that were not recognised in 1999-00		5.6		(40.9	)	(35.3	)
Gains and (losses) arising in 1999-00 that were not recognised in 1999-00		46.3		(43.2	)	3.1
Unrecognised gains and (losses) on hedges at 31 March 2000		51.9		(84.1	)	(32.2	)
Gains and (losses) expected to be recognised in 2000-01		(3.5	)	(21.8	)	(25.3	)
Gains and (losses) expected to be recognised in 2001-02 or later		55.4		(62.3	)	(6.9	)
(i) Figures in the table above are calculated by reference to the 31 March 2000 fair value of the derivative concerned.
	Notes	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	(ii)	(5.8	)	5.8		–
Transfer from losses to gains	(ii)	(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		59.4		(64.1	)	(4.7	)
Unrecognised gains and (losses) on hedges at 31 March 2001		80.4		(115.6	)	(35.2	)
Gains and (losses) expected to be recognised in 2001-02		(1.6	)	(14.1	)	(15.7	)
Gains and (losses) expected to be recognised in 2002-03 or later		82.0		(101.5	)	(19.5	)
(ii) Figures in the table above are calculated by reference to the 31 March 2001 fair value of the derivative concerned.
(i) Currency exposures As explained in the Financial Review the group uses forward contracts to mitigate the currency exposures arising from its net investment overseas. Gains and losses arising on net investment overseas and the forward contracts 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 2001 (2000 £nil). (j) Contracts for Differences The gross value of outstanding CfDs in the group’s UK businesses at 31 March 2001 was less than £0.1 million (2000 £427.2 million). The gross value of outstanding CfDs in the group’s US businesses was not material. The group estimated that the fair value amount of CfDs outstanding at the year end was £nil (2000 £1.8 million).

• UK Menu     • Cross Reference to Form 20-F (US)

Notes to the Group Balance Sheet as at 31 March 2001

22 Other creditors
	2001 £m	2000 £m
Amounts falling due within one year:
Trade creditors	214.5	208.3
Corporate tax	365.0	540.1
Other taxes and social security	45.5	15.7
Payments received on account	28.7	35.7
Capital creditors and accruals	234.1	217.6
Other creditors	387.3	302.5
Accrued expenses	981.4	632.7
Proposed dividend	119.4	113.4
	2,375.9	2,066.0

• UK Menu     • Cross Reference to Form 20-F (US)

Notes to the Group Balance Sheet as at 31 March 2001

23 Provisions for liabilities and charges – Other provisions
	At				Utilised		At
	1 April	Transferred		New	during		31 March
	1998	to creditors		provisions	year		1999
1998-99	£m	£m		£m	£m		£m
Reorganisation and restructuring	1.1	–		–	(0.4	)	0.7
Environmental and health	10.0	–		1.5	(1.4	)	10.1
Pensions	15.6	(6.8	)	–	–		8.8
Other	11.4	–		2.1	(2.3	)	11.2
	38.1	(6.8	)	3.6	(4.1	)	30.8

	At			Unwinding	Utilised			At
	1 April		New	of	during			31 March
	1999	Acquisition	provisions	discount	year		Exchange	2000
1999-00	£m	£m	£m	£m	£m		£m	£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

			Acquisition/
		At	revision to					Unwinding	Utilised			At
		1 April	provisional				New	of	during			31 March
		2000	fair values		Disposal		provisions	discount	year		Exchange	2001
2000-01	Notes	£m	£m		£m		£m	£m	£m		£m	£m
Reorganisation and restructuring	(a)	44.0	–		–		54.7	–	(17.8	)	4.2	85.1
Environmental and health	(b)	84.0	–		–		3.7	2.3	(2.4	)	9.2	96.8
Decommissioning costs	(c)	91.5	(15.2	)	(6.7	)	–	3.9	(0.8	)	9.4	82.1
Onerous contracts	(d)	79.0	171.5		–		–	6.3	(12.7	)	-	244.1
Pensions and post-retirement benefits	(e)	97.6	–		–		98.6	–	(47.6	)	16.3	164.9
Mine reclamation costs	(f)	104.8	–		(17.3	)	–	3.5	(11.8	)	11.1	90.3
Other	(g)	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
(a) The provisions for reorganisation and restructuring comprise certain costs relating to the PacifiCorp Transition Plan announced in May 2000 and 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. The provisions are principally in respect of severance costs, most of which are expected to be incurred in the period to March 2004. (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 principally over the next nine years. (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 to 31 March 2009 as follows: less than 1 year £41.4 million, between 1 and 2 years £43.6 million, between 2 and 5 years £100.3 million, and the remainder after 5 years £58.8 million. (e) Details of the group's pensions and other post-retirement benefits are disclosed in Note 31 and Note 35 . (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 Other category comprises various provisions which are not individually sufficiently material to warrant separate disclosure.

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Notes to the Group Balance Sheet as at 31 March 2001

24 Provisions for liabilities and charges – Deferred tax
Deferred tax provided in the Accounts is as follows:	Provided
	2001		2000
	£m		£m
Accelerated capital allowances	1,963.1		1,999.7
Other timing differences	(337.8	)	(387.6	)
	1,625.3		1,612.1
			£m
At 1 April 1998 – as previously stated			–
Prior year adjustment for FRS 19			709.6
At 1 April 1998 – as restated			709.6
Charge to profit and loss account			33.5
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 31 March 2001			1,625.3

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Notes to the Group Balance Sheet as at 31 March 2001

25 Deferred income
			Released to
	At	Receivable	profit		At
	1 April	during	and loss		31 March
	1999	year	account		2000
	£m	£m	£m		£m
Grants and customer contributions	393.2	49.2	(15.6	)	426.8

			Released to
	At	Receivable	profit			At
	1 April	during	and loss			31 March
	2000	year	account		Exchange	2001
	£m	£m	£m		£m	£m
Grants and customer contributions	426.8	88.6	(15.1	)	1.2	501.5
Deferred income excludes grants and contributions received in respect of water infrastructure assets.

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Notes to the Group Balance Sheet as at 31 March 2001

26 Share capital
		2001	2000
	Note	£m	£m
Authorised:
3,000,000,000 (2000 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:
1,849,025,792 (2000 1,847,585,937) ordinary shares of 50p each		924.5	923.8
One Special Share of £1	(a)	–	–
		924.5	923.8

(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 Schemes The group has five types of share based schemes 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 scheme. 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 has been replaced with the Long Term Incentive Plan and, although it will not affect options already granted, this plan supersedes executive share options. 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. 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) and 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 Plan 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
				Southern			Executive			PacifiCorp
	ScottishPower			Water			Share			Stock
	Sharesave		Weighted	Sharesave		Weighted	Option		Weighted	Incentive		Weighted
	Schemes		average	Scheme		average	Scheme		average	Plan#		average	Total
	(number of		exercise	(number of		exercise	(number of		exercise	(number of		exercise	(number of
	shares		price	shares		price	shares		price	shares		price	shares
	000s)		(pence)	000s)		(pence)	000s)		(pence)	000s)		(pence)	000s)
Outstanding at 1 April 1998	18,995		274.6	4,249		126.9	854		328.6	–		–	24,098
Granted	4,284		440.0	–		–	–		–	–		–	4,284
Exercised	(1,224	)	252.6	(1,458	)	102.9	(372	)	338.1	–		–	(3,054	)
Lapsed	(783	)	295.7	(91	)	166.6	(50	)	380.2	–		–	(924	)
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	–		–	–		–	2,982		422.2	7,727
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	(1,478	)	578.1	(3,970	)
Outstanding at 1 April 2000	19,945		339.2	1,078		147.1	263		297.0	16,038		534.5	37,324
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	)	–	(2,826	)	617.5	(5,417	)
Outstanding at 31 March 2001	16,212		355.6	279		149.3	140		316.1	13,365		592.3	29,996
* PacifiCorp share options as at 29 November 1999. # 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.

(ii) Analysis of share options outstanding at 31 March 2001
			Number of	Option
	Date of	Number of	shares	price
	grant	participants	(000s)	(pence)	Normal exercisable date
ScottishPower Sharesave Schemes	20 June 1996	2,552	5,956	263.1	6 months to Mar 2002
	20 June 1997	1,846	2,289	307.0	6 months to Mar 2003
	12 June 1998	3,810	2,750	440.0	6 months to Mar 2002 or 2004
	11 June 1999	4,293	3,187	429.0	6 months to Mar 2003 or 2005
	9 June 2000	3,326	2,030	453.0	6 months to Mar 2004 or 2006
Southern Water Sharesave Scheme	25 Jan 1994	46	78	154.9	6 months to Sep 2001
	25 Jan 1995	39	109	136.1	6 months to Sep 2002
	25 Jan 1996	56	92	160.2	6 months to Sep 2001 or 2003
Executive Share Option Scheme	18 Dec 1991	3	40	227.4	1994-2001
	25 June 1992	5	4	237.7	1995-2002
	1 July 1993	2	28	310.0	1996-2003
	17 Dec 1993	14	20	454.8	1996-2003
	27 May 1994	2	1	354.0	1997-2004
	18 Nov 1994	2	21	352.1	1997-2004
	12 May 1995	3	26	335.0	1998-2005
PacifiCorp Stock Incentive Plan**	3 June 1997	88	1,525	599.6	29 Nov 1999 to 3 June 2007
	12 Aug 1997	24	261	645.1	29 Nov 1999 to 12 Aug 2007
	10 Feb 1998	108	2,617	728.5	29 Nov 1999 to 10 Feb 2008
	13 May 1998	5,815	1,343	704.0	29 Nov 1999 to 13 May 2008
	9 Feb 1999	112	3,190	576.8	9 Feb 2000 to 9 February 2009	##
	11 May 1999	6,133	1,413	521.8	11 May 2000 to 11 May 2009	***
	16 Feb 2000	110	2,559	474.3	16 Feb 2001 to 16 Feb 2010	###
	25 Jan 2001	2	457	441.3	25 Jan 2002 to 25 Jan 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 2001 to be quoted in pence in the table above. ## Options became exercisable in the proportions of one-third on 9 February 2000, with a further third on 9 February 2001 and the remaining one-third becomes exercisable on 9 February 2002. *** Options became exercisable in the proportions 50% on 11 May 2000 and the remaining 50% becomes exercisable on 11 May 2001. ### Options became exercisable in the proportions of one-third on 16 February 2001, with a further third becoming exercisable on 16 February 2002 and the remaining one-third becomes exercisable on 16 February 2003. #### Options will become 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 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.

• UK Menu     • Cross Reference to Form 20-F (US)

Notes to the Group Balance Sheet as at 31 March 2001

27 Analysis of movements in shareholders' funds

Number of shares

Share capital

Share premium

Revaluation reserve

Capital redemption reserve

Merger reserve

Other reserve

Profit and loss account

Total

Notes

000s

£m

£m

£m

£m

£m

£m

£m

£m

At 1 April 1998 – as originally stated

1,196,752

598.4

–

227.3

–

388.7

&3150;

493.4

1,707.8

Prior year adjustment for FRS 19

–

–

–

–

–

–

–

(709.6

)

(709.6

)

At 1 April 1998 – as restated

1,196,752

598.4

–

227.3

–

388.7

–

(216.2

)

998.2

Retained profit for the year

–

–

–

–

–

–

–

201.4

201.4

Share capital issued

– Employee sharesave scheme

1,554

0.8

4.2

–

–

–

(3.1

)

–

1.9

– Executive share option scheme

372

0.2

1.1

–

–

–

–

–

1.3

Revaluation surplus realised

–

–

–

(3.4

)

–

–

–

3.4

–

Transfers

–

–

(5.3

)

–

–

5.3

3.1

(3.1

)

–

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

(a)

–

–

–

–

–

–

–

7.5

7.5

Goodwill realised on disposals

(a)

–

–

–

–

–

–

–

15.3

15.3

Share buy–back

(52,973

)

(26.5

)

–

–

26.5

–

–

(302.0

)

(302.0

)

Exchange movements

(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 movements

(b)

–

–

–

–

–

–

–

493.1

493.1

Balance at 31 March 2001

1,849,026

924.5

3,739.7

217.1

18.3

406.4

–

587.2

5,893.2

(a) Cumulative goodwill written off to reserves as at 31 March 2001 was £1,349.9 million (2000 £1,349.9 million, 1999 £1,372.7 million). (b) The cumulative foreign currency translation adjustments at 31 March 2001 amount to £518.0 million (2000 £24.9 million, 1999 £nil). (c) 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.

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Notes to the Group Balance Sheet as at 31 March 2001

28 Minority interests
	Equity		Non-equity		Total		Equity		Non-equity	Total
	2001		2001		2001		2000		2000	2000
	£m		£m		£m		£m		£m	£m
At 1 April	161.6		138.1		299.7		1.3		–	1.3
Acquisition	–		–		–		0.2		134.8	135.0
Arising on partial disposal of Thus	–		–		–		162.2		–	162.2
Disposal	–		–		–		(0.8	)	–	(0.8	)
Exchange	–		19.5		19.5		–		0.9	0.9
Profit and loss account	(33.4	)	10.4		(23.0	)	(1.3	)	2.4	1.1
Dividends paid to minority interests	–		(10.4	)	(10.4	)	–		–	–
At 31 March	128.2		157.6		285.8		161.6		138.1	299.7
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 2001, £75.7 million is due to be redeemed within 1 year, £2.6 million is due to be redeemed in each of the next 4 years with the remaining £42.4 million being redeemable after 5 years. The fair value of preferred stock subject to mandatory redemption is £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% and on other preferred stock is 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.

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Notes to the Group Balance Sheet as at 31 March 2001

29 Acquisition
In March 2001, the group acquired the business and assets of Rye House power station for a total consideration of £227.7 million. The acquisition method of accounting has been adopted and the goodwill on the purchase has been capitalised and is being amortised over 20 years. The directors have estimated the useful economic life of the goodwill acquired after assessment of the earnings generating life of the plant. The details of the transaction are shown below.
	Provisional
	fair values
Fair value of Rye House consideration	£m
Tangible fixed assets	300.0
Stocks	2.1
Debtors	1.8
Creditors: amounts falling due within one year	(1.8	)
Provisions for liabilities and charges	(171.5	)
Net assets	130.6
Goodwill arising on acquisition of Rye House	97.1
Purchase consideration	227.7
Satisfied by:
Cash paid	217.2
Acquisition expenses	10.5
	227.7
The net assets of the Rye House power station did not form part of a separate legal entity acquired and therefore no information on book values is available. The tangible fixed assets acquired have been provisionally fair valued at net depreciated replacement cost and a provision for an onerous gas contract has been established by reference to market prices prevailing at the time of the acquisition. The post-acquisition results and cash flows of the Rye House business are not material to the group’s results and cash flows for the year ended 31 March 2001. The fair values attributed to the acquisition are provisional due to the proximity of the date of acquisition to the financial year end.

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Notes to the Group Balance Sheet as at 31 March 2001

30 Revision to provisional fair values of PacifiCorp
On 29 November 1999 the group acquired PacifiCorp for a total consideration of £4,111.3 million. As set out in the March 2000 Accounts the fair values of the assets and liabilities of PacifiCorp, established for the purposes of those Accounts, were provisional due to the size and complexity of the acquisition. In the year ended 31 March 2001 these fair values have been finalised as permitted by FRS 7. The details of the adjustments to the provisional fair values are set out below.
							Revisions to
							provisional
							fair values		Revisions
	Provisional						attributable to		to other
	fair values		Prior year		Provisional		businesses		provisional
	as previously		adjustment		fair values		held for		fair values		Final fair
	stated		(Note a)		as restated		disposal		(Note b)		values
Fair value of PacifiCorp consideration	£m		£m		£m		£m		£m		£m
Tangible fixed assets	4,882.6		–		4,882.6		–		(222.6	)	4,660.0
Investments	123.8		–		123.8		–		–		123.8
Businesses held for disposal	551.0		–		551.0		1.4		–		552.4
Current assets	1,030.3		–		1,030.3		–		(155.7	)	874.6
Creditors: amounts falling due within one year
– Loans and other borrowings	(199.1	)	–		(199.1	)	–		–		(199.1	)
– Other creditors	(844.0	)	92.6		(751.4	)	–		(150.8	)	(902.2	)
Creditors: amounts falling due after more than one year
– Loans and other borrowings	(2,366.5	)	–		(2,366.5	)	–		–		(2,366.5	)
Provisions for liabilities and charges	(533.1	)	(668.7	)	(1,201.8	)	–		113.7		(1,088.1	)
Minority interest	(135.0	)	–		(135.0	)	–		–		(135.0	)
Net assets	2,510.0		(576.1	)	1,933.9		1.4		(415.4	)	1,519.9
Goodwill arising on acquisition of PacifiCorp	1,601.3		576.1		2,177.4		(1.4	)	415.4		2,591.4
Purchase consideration	4,111.3				4,111.3						4,111.3
(a) Prior year adjustment The provisional fair values attributed to the net assets of PacifiCorp have been restated for the effects of the implementation of the group's new accounting policy for deferred tax in accordance with FRS 19 (see Note 6 ). (b) Revisions to provisional fair values of PacifiCorp Revisions have been made during the year ended 31 March 2001 to the provisional fair values originally attributed to the net assets of PacifiCorp in the March 2000 Accounts. The principal revisions are: (i) at the time of the PacifiCorp acquisition, various regulatory rates cases and depreciation studies were outstanding. All of these have now been concluded and tangible fixed assets have been written down by £222.6 million following the outcome. (Ii) US regulatory assets, included within debtors, have been reduced by £137.8 million following reassessment of their recoverability in the context of the US regulatory regime. (iii) provision of £150.8 million has been made for liabilities for taxation, including related interest, arising out of US tax authorities' audits of PacifiCorp's pre–acquisition tax computations and other liabilities including legal costs. (iv) the deferred tax effect of the above adjustments.

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Notes to the Group Balance Sheet as at 31 March 2001

31 Pensions
At 31 March 2001, 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. 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 charge for the year				Prepayment/      (provision)      as at 31 March
			Scheme			Funded or		2001		2000		1999		2001		2000
Pension Fund			type			unfunded		£m		£m		£m		£m		£m
ScottishPower			Defined benefit			funded		–		–		6.9		5.0		5.0
Manweb			Defined benefit			funded		4.3		4.2		5.8		–		–
Southern Water			Defined benefit			funded		3.7		4.1		5.3		–		–
Final Salary LifePlan			Defined benefit			funded		3.0		1.0		–		–		–
PacifiCorp*			Defined benefit			funded		63.7	**	5.3	***	–		(85.9	)	(32.6	)
* The PacifiCorp figures include the unfunded Supplementary Executive Retirement Plan (SERP). The SERP accounts for less than 5% of the PacifiCorp liabilities. ** Includes £54.8m 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:
				2001								2000
				Interest								Interest
				(credit)/								(credit)/
				cost on				Net				cost on				Net
			Regular	prepayment/		Variation		pension		Regular		prepayment/		Variation		pension
			cost	provision		credit		charge		cost		provision		credit		charge
Pension Fund			£m	£m		£m		£m		£m		£m		£m		£m
ScottishPower*			26.5	(0.3	)	(39.5	)	–		33.0		(0.3	)	(47.1	)	–
Manweb			5.8	–		(1.5	)	4.3		5.8		–		(1.6	)	4.2
Southern Water			4.7	–		(1.0	)	3.7		5.3		–		(1.2	)	4.1
Final Salary LifePlan			3.0	–		–		3.0		1.0		–		–		1.0
PacifiCorp**			12.6	5.8		45.3	***	63.7		4.4		0.9		–		5.3
* The net pension charge is set to a minimum of nil where the variation credit exceeds regular cost plus interest. ** Relating to post 29 November 1999 only for the year to 31 March 2000. *** Being a normal variation credit of £9.5m increased by the cost of Special Termination Benefits of £54.8m. The prepayment/(provision) as at the year end can be reconciled as follows:
Prepayment/							Prepayment/			Prepayment/						Prepayment/
(provision)							(provision)			(provision)						(provision)
at 1 April			Employer	Pension			at 31 March			at 1 April		Employer		Pension		at 31 March
	2000	contribution		charge		Exchange		2001		1999		contribution		charge		2000
Pension Fund	£m		£m	£m		£m		£m		£m		£m		£m		£m
ScottishPower	5.0		–	–		–		5.0		5.0		–		–		5.0
Manweb	–		4.3	(4.3	)	–		–		–		4.2		(4.2	)	–
Southern Water	–		3.7	(3.7	)	–		–		–		4.1		(4.1	)	–
Final Salary LifePlan	–		3.0	(3.0	)	–		–		–		1.0		(1.0	)	–
PacifiCorp*	(32.6	)	16.6	(63.7	)	(6.2	)	(85.9	)	(37.5	)**	10.2		(5.3	)	(32.6	)
* The PacifiCorp figures for the year to 31 March 2000 relate to the post-acquisition period only. ** Arising on acquisition as at 29 November 1999.

The individual scheme funding details and assumptions made are as follows:
								Principal actuarial assumptions
			Value								Value
	Latest		of assets	Market		Average				Average	of fund
	full	Valuation	based on	value of	Valuation	investment		Average	Average	equity	assets/
	actuarial	carried	valuation	assets	method	rate of		pension	salary	dividend	accrued
Pension fund	valuation	out by	£m	£m	adopted	return		increases	increases	growth	benefits
ScottishPower	31 March 2000	William M Mercer	1,930.4	2,090.4	Projected unit	6.0%		4.5%	2.5%	n/a	129%
Manweb	31 March 1998	Bacon & Woodrow	467.6	613.7	Projected unit	8.5%		6.5%	4.5%	4.75%	105%
Southern Water	31 March 1998	Watson Wyatt	231.1	298.6	Projected unit	8.5%		6.5%	4.5%	5.5%	108%
Final Salary LifePlan	31 March 1999	William M Mercer	0.1	0.1	Projected unit	5.5%		4.0%	2.5%	n/a	97%
PacifiCorp	1 January 2000	Hewitt Associates	840.3	840.3	Projected unit	9.25%/7.5%	*	4.0%	–	n/a	112%
* 9.25% represents the expected return on assets and 7.5% represents the liability discount rate.
(a) Group pension arrangements Following a review of the group's UK pension arrangements, the ScottishPower Pension Scheme, Manweb 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, subject to any qualifying period of service required by the group. 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) . 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 2001 are as follows:

	Equities	Bonds	Property	Cash	Total
	%	%	%	%	%
ScottishPower	87	4	8	1	100
Manweb	69	30	–	1	100
Southern Water	71	25	–	4	100
Final Salary LifePlan	100	–	–	–	100
PacifiCorp	69	31	–	–	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 1,021,570 ScottishPower shares (£4,780,948, based on market value as at 31 March 2001), 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 expensing calculations detailed above resulted in the accounting rate used for the calculation of the 2000–01 pension charge being £nil. This 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.

(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 pay 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. On average, the company pays contributions at twice the rate payable by the member.

The assets are held in a separate trustee administered fund. Included in the Scheme assets are 202,797 ScottishPower shares (£949,090 based on market value as at 31 March 2001), purchased only as part of a pooled strategy to match the relative weightings in the UK Stock Exchange index. 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 12% of pensionable salaries, 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 three years and an annual charge in respect of Early Retirement Deficiency Costs payable over 14 years.

(d) Southern Water
Southern Water operates a number of pension schemes. 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 10.0% of pensionable salaries, 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.

(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 of 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.

(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 35 .

(g) Additional pension 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 35 .

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Notes to the Group Balance Sheet as at 31 March 2001

32 Contingent liabilities

Thus Flotation
In November 1999, the group floated a minority stake in its Internet and telecommunications business, Thus plc. In the event that Thus plc ceases to be a part of the ScottishPower capital gains tax group before 30 September 2005, Thus plc will become liable to corporation tax on chargeable gains currently estimated, after consideration of various uncertainties, at amounts up to £570 million. Members of the ScottishPower group have agreed to indemnify Thus 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.

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Notes to the Group Balance Sheet as at 31 March 2001

33 Financial commitments
	2001	2000
(a) Analysis of annual commitments under operating leases	£m	£m
Leases of land and buildings expiring:
Within one year	0.6	0.4
Between one and two years	1.7	1.2
Between two and three years	0.6	1.2
Between three and four years	0.5	1.2
Between four and five years	0.8	0.1
More than five years	28.7	23.4
	32.9	27.5
Other operating leases expiring:
Within one year	13.8	14.4
Between one and two years	8.4	1.0
Between two and three years	3.5	7.7
Between three and four years	0.9	0.9
Between four and five years	0.5	2.7
More than five years	0.1	1.0
	27.2	27.7
	2001	2000
(b) Capital commitments	£m	£m
Contracted but not provided	174.9	286.5

(c) Other contractual commitments Under contractual commitments in the UK the group has rights and obligations in relation to the undernoted contracts. The annual value of the purchases and sales arising from these contracts is provided below:
				Purchases/sales in year
				under group commitments
		Commitment	Commitment	2001	2000	1999
	Note	entered into	expires	£m	£m	£m
The purchase of electricity from British Energy Generation (UK) Limited		1990	2005	265.8	370.1	367.7
The purchase of electricity from Scottish and Southern Energy plc	(i)	1990	see below	49.7	72.4	78.8
The supply of electricity to Scottish and Southern Energy plc		1990	2005	17.6	17.6	18.2
Revenue from the operation of the company’s transmission system and access by Scottish and Southern Energy plc to the Anglo-Scottish Interconnector		1990	No fixed date of expiry	32.4	31.0	27.7
Purchase of coal from The Scottish Coal Company Limited		1998	2003	41.0	19.0	22.0
Purchase of coal from The Scottish Coal (Deep Mine) Company Limited		1998	2004	44.8	49.2	50.5
Purchase of gas from various fields in the North Sea		1994	2017	172.0	125.8	123.6

(i) There are two agreements relating to the purchase of electricity from Scottish and Southern Energy plc. These expire in 2012 and 2039. In the US, the group 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 £331.9 million, £310.8 million, £196.2 million, £163.2 million and £139.9 million for the years 2002 to 2006 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 £296.1 million, £282.7 million, £237.7 million, £226.4 million and £224.3 million for the years 2002 to 2006 respectively. The purchase contracts include agreements with the Bonneville Power Administration, the Hermiston Plant and a number of cogenerating facilities. (ii) Under the terms of the agreement to dispose of the group's UK technology, contracting and information technology divisions during the year ended 31 March 2001, the group has entered into purchase commitments with the purchasers of these businesses. The purchase commitments under these agreements at 31 March 2001 are:
	2002	2003	2004	2005	Total
	£m	£m	£m	£m	£m
Commitment to purchase in year	101.4	99.1	92.0	92.0	384.5

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Notes to the Group Balance Sheet as at 31 March 2001

34 Related party transactions
Related party transactions and balances with joint ventures and associated undertakings   (a) Trading transactions and balances arising in the normal course of business
		Sales/(purchases)						Amounts due
		to/(from) other						from/(to) other
		group companies						group companies
		during the year						as at 31 March
		2001		2000		1999		2001		2000
Related party	Related party relationship to group	£m		£m		£m		£m		£m
Sales by related parties
Scottish Electricity Settlements Limited	50% owned joint venture	6.2		8.7		5.8		1.4		1.7
ScotAsh Limited	50% owned joint venture	0.4		0.2		–		0.4		–
South Coast Power Limited	50% owned joint venture	25.1		–		–		3.5		–
Calanais Limited*	50% owned joint venture	69.0		–		–		0.6		–
Purchases by related parties
Scottish Electricity Settlements Limited	50% owned joint venture	(0.2	)	(0.4	)	(0.9	)	–		–
ScotAsh Limited	50% owned joint venture	(0.2	)	(0.3	)	–		(0.2	)	(0.1	)
South Coast Power Limited	50% owned joint venture	(3.2	)	(0.3	)	(8.1	)	(0.6	)	(0.1	)
CeltPower Limited	50% owned joint venture	(0.3	)	(0.4	)	(0.1	)	–		(0.1	)
Calanais Limited*	50% owned joint venture	(13.0	)	–		–		(0.8	)	–

In addition to the above, during the year to 31 March 2001, PacifiCorp has made management and similar charges to Powercor of £1.4 million (30 November 1999 to 31 March 2000 £2.0 million). At 31 March 2001, Powercor owed the group £nil (2000 £21.9 million). *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. (b) Funding transactions and balances arising in the normal course of business
		Interest payable				Amounts due
		to other group				to other
		companies during				group companies
		the year				as at 31 March
		2001		2000		2001		2000
Related party	Related party relationship to group	£m		£m		£m		£m
Scottish Electricity Settlements Limited	50% owned joint venture	(1.4	)	(1.4	)	(16.6	)	(18.3	)
ScotAsh Limited	50% owned joint venture	–		–		(3.0	)	(1.0	)
RoboScot (38) Limited	50% owned joint venture	–		–		(5.4	)	–

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Notes to the Group Balance Sheet as at 31 March 2001

35 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 profit for the financial year and equity shareholders’ funds are set out in the tables below.
		2001		2000		1999
(a) Reconciliation of profit for the financial year to US GAAP:	Notes	£m		£m		£m
Profit for the financial year under UK GAAP		307.5		885.0		469.3
US GAAP adjustments:
Amortisation of goodwill	(i)	(35.9	)	(34.4	)	(33.7	)
US regulatory assets	(ii)	73.8		–		–
Pensions	(iii)	95.5		44.8		17.6
Depreciation on revaluation uplift	(iv)	3.4		3.4		3.4
Decommissioning and mine reclamation liabilities	(v)	(32.3	)	(6.7	)	–
PacifiCorp Transition Plan costs	(ii)	108.2		–		–
Other	(xi)	(0.4	)	(8.0	)	–
Re-classification as extraordinary item	(vi)	–		15.9		–
		519.8		900.0		456.6
Deferred tax effect of US GAAP adjustments	(vii)	(133.0	)	(19.2	)	(5.3	)
		386.8		880.8		451.3
Extraordinary item (net of tax)	(vi)	–		(11.1	)	–
Profit for the financial year under US GAAP		386.8		869.7		451.3
Earnings per share under US GAAP – continuing operations		21.13	p	63.39	p	38.08	p
– extraordinary item (net of tax)	(vi)	–		(0.80	)p	–
Earnings per share under US GAAP	(x)	21.13	p	62.59	p	38.08	p
Diluted earnings per share under US GAAP – continuing operations		21.05	p	62.95	p	37.70	p
– extraordinary item (net of tax)	(vi)	–		(0.79	)p	–
Diluted earnings per share under US GAAP	(x)	21.05	p	62.16	p	37.70	p

(b) Effect on equity shareholders’ funds of differences between UK GAAP and US GAAP:
		2001		2000
	Notes	£m		£m
Equity shareholders’ funds under UK GAAP		5,893.2		5,563.3
US GAAP adjustments:
Goodwill	(i)	1,349.9		1,349.9
Business combinations	(i)	(188.7	)	16.0
Amortisation of goodwill	(i)	(172.7	)	(136.4	)
ESOP shares held in trust	(viii)	(51.1	)	(62.3	)
US regulatory assets	(ii)	661.2		348.1
Pensions	(iii)	245.0		150.3
Dividends	(ix)	119.4		113.4
Revaluation of fixed assets	(iv)	(229.0	)	(229.0	)
Depreciation on revaluation uplift	(iv)	11.9		8.5
Decommissioning and mine reclamation liabilities	(v)	82.5		123.3
PacifiCorp Transition Plan costs	(ii)	117.2		–
Other	(xi)	12.1		10.2
Deferred tax:
Effect of US GAAP adjustments	(vii)	(351.0	)	(213.6	)
Effect of differences in methodology	(vii)	(37.0	)	(41.0	)
Equity shareholders’ funds under US GAAP		7,462.9		7,000.7

(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 against reserves. Goodwill arising on acquisitions after 31 March 1998 is capitalised and amortised through the income statement 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 economic 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, Southern Water 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) 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 United States 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 £778.4 million (2000 £348.1 million) are not recognised under UK GAAP, including deferred excess power costs and PacifiCorp Transition Plan costs.

Profits under US GAAP are consequently increased by £182.0 million in 2001 (2000 £nil), representing the deferral of costs expensed under UK GAAP net of amortisation of regulatory assets recognised under US GAAP.

PacifiCorp Transition Plan costs are also accounted for as regulatory assets under US GAAP but have been separately identified in view of their significance.

(iii) 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.

(iv) Revaluation of fixed assets
The revaluation of Manweb distribution assets and Southern Water operational assets is not permitted under US GAAP. Accordingly, the reconciliation restates fixed assets to historical cost and the depreciation charge has been adjusted. Refer to Note 17 (i) for further information relating to the fixed assets revaluation.

(v) 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.

(vi) 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. Earnings per share under US GAAP are shown both before and after extraordinary items.

(vii) Deferred tax
Under UK GAAP, Financial Reporting Standard 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.

(viii) ESOP shares held in trust
Under UK GAAP, shares held by an Employee Share Ownership Plan (ESOP) 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. No dividends have been paid on the shares held by the ScottishPower ESOP and future dividends have been waived.

(ix) Ordinary dividends
Under UK GAAP, final ordinary 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.

(x) Earnings per share
Under UK GAAP, earnings per share is calculated by dividing the net profit for the period by the weighted average number of shares (for basic and diluted number of shares) outstanding for the period. UK GAAP permits the presentation of more than one measure of earnings per share provided that all such measures are clearly explained and are given equal prominence on the face of the income statement.

Under US GAAP, earnings per share is calculated by dividing earnings from continuing operations, excluding extraordinary items, by the weighted average number of shares (for basic and diluted number of shares) outstanding for the period. US GAAP permits only one measure of earnings per share as a performance measure.

(a) Earnings per ordinary share have been calculated by dividing the 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:

	2001	2000	1999
Profit for the financial year under US GAAP (£m)	386.8	869.7	451.3
Basic weighted average share capital (number of shares, millions)	1,830.3	1,389.6	1,185.2
Diluted weighted average share capital (number of shares, millions)	1,837.4	1,399.2	1,197.2
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. (b) As permitted under UK GAAP, 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. In accordance with US GAAP, earnings per share have been presented above based on US GAAP earnings, without adjustments for the impact of exceptional items, other than those which are classified as extraordinary items under US GAAP, and goodwill amortisation. Such additional measures of underlying performance are not permitted under US GAAP. The inclusion of exceptional items, other than those which are classified as extraordinary items under US GAAP, in the determination of earnings per share in accordance with US GAAP increased earnings by £408.9 million or 29.43 pence per share for the year ended 31 March 2000. The inclusion of goodwill amortisation decreased earnings by £163.5 million or 8.93 pence per share for the year ended 31 March 2001, by £74.8 million or 5.38 pence per share for the year ended 31 March 2000 and by £34.9 million or 2.94 pence per share for the year ended 31 March 1999. (xi) 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, marketable securities, energy exchange contracts and stock option 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. 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. 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. 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 profit for financial year under US GAAP and earnings per share under US GAAP would have been reduced to the pro forma amounts below:

For the year	2001		2000
Profit for financial year under US GAAP (£m)	386.8		869.7
Pro forma (£m)	380.6		864.6
Earnings per share under US GAAP	21.13	p	62.59	p
Pro forma	20.79	p	62.22	p
The effect on 1999 profit for the financial year under US GAAP and earnings per share would have been immaterial. The weighted average fair value of options granted during the year was £1.6 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:

For the year	2001		2000
Dividend yield	6.4	%	4.5	%
Risk-free interest rate	4.9	%	6.0	%
Volatility	24.0	%	30.0	%
Expected life of the options (years)	4		4

The weighted average life of the share options outstanding as at 31 March 2001 and March 2000 was as follows:
	2001	2000
	(years)	(years)
ScottishPower Sharesave Schemes	2	3
Southern Water Sharesave Scheme	2	2
Executive Share Option Scheme	2	2
PacifiCorp Stock Incentive Plan	6	8

(xii) Reclassifications
The reconciliations of 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 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 special charges 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 income.

The consolidated statement of comprehensive income is set out below:
	2001		2000	1999
	£m		£m	£m
Profit for the financial year under US GAAP	386.8		869.7	451.3
Other comprehensive income
– Foreign currency translation adjustment	670.8		25.1	–
– Unrealised (loss)/gain on available-for-sale securities	(4.6	)	2.0	–
Total comprehensive income under US GAAP	1,053.0		896.8	451.3
The accumulated balances related to each component of other comprehensive income are as follows; foreign currency translation adjustment £695.9 million (2000 £25.1 million) and unrealised loss on available-for-sale securities £2.6 million (2000 £2.0 million unrealised gain). 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 associates and 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 associates and 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. The consolidated cash flow statement prepared in conformity with UK GAAP is set out here . 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 associates and 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:
	2001		2000		1999
	£m		£m		£m
Cash inflow from continuing operating activities	1,411.6		1,117.5		944.9
Dividends received from associates and joint ventures	2.1		0.5		0.9
Returns on investments and servicing of finance	(373.5	)	(258.4	)	(149.9	)
Ordinary taxation	(152.6	)	(154.3	)	(93.7	)
Windfall tax	–		–		(157.8	)
Net cash provided by operating activities	887.6		705.3		544.4
Capital expenditure and financial investment	(1,081.4	)	(842.3	)	(683.0	)
Acquisitions and disposals	482.9		718.8		(77.4	)
Net cash used in investing activities	(598.5	)	(123.5	)	(760.4	)
Financing	196.1		(121.2	)	454.2
Add: movement in bank overdrafts	11.1		23.8		6.0
Equity dividends paid	(471.3	)	(406.0	)	(252.8	)
Net cash (required)/provided by financing activities	(264.1	)	(503.4	)	207.4
Net increase/(decrease) in cash and cash equivalents	25.0		78.4		(8.6	)
Exchange movement on cash and cash equivalents	19.9		–		–
Cash and cash equivalents at beginning of financial year	185.3		106.9		115.5
Cash and cash equivalents at end of financial year	230.2		185.3		106.9
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	2001 £m	2000 £m	1999 £m
On acquisition of subsidiaries:
Shares allotted as part of purchase consideration	–	4,065.5	–

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) Deferred tax The additional components of the estimated net deferred tax liability that would be recognised under US GAAP are as follows:
	2001 £m		2000 £m
Deferred tax liabilities:
Excess of book value over taxation value of fixed assets	186.0		167.6
Other temporary differences	208.0		107.0
	394.0		274.6
Deferred tax assets:
Other temporary differences	(6.0	)	(20.0	)
Net deferred tax liability	388.0		254.6
Analysed as follows:
Current	(6.0	)	(20.0	)
Non-current	394.0		274.6
	388.0		254.6

(c) Pensions At 31 March 2001, 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 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. 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 2001, 31 March 2000 and 31 March 1999 are as follows:
Change in benefit obligation	2001 £m		2000 £m		1999 £m
Benefit obligation at beginning of year	2,827.6		2,074.2		1,882.4
Additional obligation from acquisition	–		673.6		–
Service cost (excluding plan participants’ contributions)	66.6		57.6		36.4
Interest cost	179.8		137.7		149.6
Plan amendments	(15.7	)	–		–
Special termination benefits	54.8		–		–
Plan participants’ contributions	12.9		12.9		13.0
Actuarial loss/(gain)	27.4		(8.3	)	97.2
Benefits paid	(187.0	)	(124.9	)	(104.4	)
Exchange	84.6		4.8		–
Benefit obligation at end of year	3,051.0		2,827.6		2,074.2
Change in plans’ assets	2001 £m		2000 £m		1999 £m
Fair value of plans’ assets at beginning of year	3,886.8		2,781.4		2,372.1
Additional fair value of assets from acquisition	–		636.1		–
Actual return on plans’ assets	(248.2	)	558.3		488.7
Employer contributions	32.7		17.7		12.0
Plan participants’ contributions	12.9		12.9		13.0
Benefits paid	(187.0	)	(124.9	)	(104.4	)
Exchange	89.4		5.3		–
Fair value of plans’ assets at end of year	3,586.6		3,886.8		2,781.4
Reconciliation of funded status to prepaid benefit cost	2001 £m		2000 £m		1999 £m
Funded status	535.6		1,059.2		707.2
Unrecognised net actuarial gain	(348.9	)	(933.5	)	(600.0	)
Unrecognised prior service cost	(15.2	)	–		–
Unrecognised Transition Obligation Asset	(2.5	)	(3.3	)	(4.2	)
Prepaid benefit cost	169.0		122.4		103.0
For all plans, the value of assets exceeded the Accumulated Benefit Obligation at the end of the year.

The components of pension benefit costs for the years ended 31 March 2001, 2000 and 1999 were as follows (figures for 2000 include post–acquisition period only for PacifiCorp):
	2001 £m		2000 £m		1999 £m
Service cost	66.6		57.6		49.4
Interest cost	179.8		137.7		149.6
Expected return on plans’ assets	(287.2	)	(211.1	)	(184.4	)
Amortisation of experience gains	(36.0	)	(22.8	)	(13.4	)
Amortisation of prior service cost	(1.1	)	–		–
Amortisation of Transition Obligation Asset	(0.8	)	(0.8	)	(0.8	)
Net periodic benefit (credit)/cost	(78.7	)	(39.4	)	0.4

The actuarial assumptions adopted in arriving at the above figures are as follows:
UK arrangements – assumptions at:	31 March 2001	31 March 2000	31 March 1999
Expected return on plans’ assets	n/a	n/a	7% p.a.
Discount rate	5.75% p.a.	6% p.a.	6% p.a.
Rate of earnings increase	4.5% p.a.	5% p.a.	5% p.a.
Pension increases	2.5% p.a.	3% p.a.	3% p.a.

US arrangements – assumptions at:	31 March 2001	31 March 2000	29 November 1999
Expected return on plans’ assets	9.25% p.a.	9.25% p.a.	9.25% p.a.
Discount rate	7.75% p.a.	7.5% 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.

(d) 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 expense on a pay–as–you–go basis and has unfunded accrued liability of £99.6 million at 31 March 2001. 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 2000 to 31 March 2001. These funds are invested in common stocks, bonds and United States 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:
	2001 £m		2000 £m	*
Service cost	3.5		1.2
Interest cost	18.8		5.1
Expected return on plan assets	(19.1	)	(4.6	)
Net periodic post-retirement benefit cost	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:
Change in accumulated post-retirement benefit obligation	2001 £m		2000 £m	*
Accumulated post–retirement benefit obligation at beginning of year	220.3		215.9	**
Service cost	3.5		1.2
Interest cost	18.8		5.1
Plan participants’ contributions	3.2		0.6
Special termination benefit loss	11.4		–
Actuarial gain	(3.1	)	(0.3	)
Benefits paid	(13.6	)	(3.7	)
Exchange	27.5		1.5
Accumulated post–retirement obligation at end of year	268.0		220.3

* For the post–acquisition period (29 November 1999 to 31 March 2000) ** As at acquisition – 29 November 1999
Change in plan assets	2001 £m		2000 £m	*
Plan assets at fair value at beginning of year	200.2		163.9	**
Actual return on plan assets	(18.2	)	31.0
Company contributions	6.8		7.0
Plan participants’ contributions	3.2		0.6
Benefits paid	(13.6	)	(3.7	)
Exchange	23.5		1.4
Plan assets at fair value at end of year	201.9		200.2
* For the post–acquisition period (29 November 1999 to 31 March 2000) ** As at acquisition – 29 November 1999

Reconciliation of accrued post-retirement costs and total amount recognised	2001 £m		2000 £m
Funded status of plan	(66.1	)	(20.1	)
PacifiCorp unrecognised net gain	6.0		(26.4	)
Accrued post-retirement benefit cost	(60.1	)	(46.5	)

The actuarial assumptions adopted in arriving at the above figures are as follows:
US arrangements – assumptions at:	31 March 2001 £m	31 March 2000 £m
Expected return on plans’ assets	9.25% p.a.	9.25% p.a.
Discount rate	7.75% p.a.	7.50% p.a.
Initial healthcare cost trend – under 65	6.00% p.a.	6.60% p.a.
Initial healthcare cost trend – over 65	6.50% p.a.	6.80% p.a.
Initial healthcare cost trend rate	4.50% p.a.	4.50% p.a.

The assumed healthcare cost trend rate gradually decreases over fourteen 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 2001 by £13.1 million (2000 £15.7 million), and the annual net periodic post–retirement benefit costs by £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 2001 by £16.0 million (2000 £14.9 million), and the annual net periodic post-retirement benefit costs by £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 £12.0 million at 31 March 2001 (2000 £11.5 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 United States employees may defer up to 16% 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 £12.2 million in the period from 1 April 2000 to 31 March 2001.

Recent US accounting pronouncements
Accounting for Derivative Instruments and Hedging Activities
In June 1998, the Financial Accounting and Standards Board (FASB) issued FAS 133 'Accounting for Derivative Instruments and Hedging Activities' which, as amended, will be effective for the group for financial years commencing on 1 April 2001. The statement establishes accounting and reporting standards that require that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. Changes in the derivative's fair value will be recognised concurrently in earnings unless specific hedge accounting criteria are met.

The group has considered the application of this standard to its operations and has completed an assessment of the impact of this standard. Due to the initial uncertainty of the implementation date of the New Electricity Trading Arrangements (NETA) and the effect this had on the re-negotiation of contractual terms, the group assessed the impact of FAS 133 on the relevant pre–NETA contractual terms and conditions. The group estimates that, the cumulative post-tax effect of adopting FAS 133, as amended, under the pre-NETA contractual terms and conditions, will decrease net income by £92.0 million and increase other comprehensive income by £421.3 million. However, the transition effect, as of 31 March 2001, is subject to change. The group continues to assess the application and impact of this standard, particularly in the light of recent discussions of the Derivative Implementation Group (DIG). The FASB and DIG continue to address FAS 133 implementation issues, and their conclusions may require changes in the group's current interpretations of the standard. At this time the group is not able to quantify the potential financial statement impact of the matters and conclusions which are under consideration by the FASB and DIG.

• UK Menu     • Cross Reference to Form 20-F (US)

Company Balance Sheet as at 31 March 2001

		2001		2000
	Notes	£m		£m
Fixed assets
Investments	36	4,746.4		4,746.3
Current assets
Debtors	37	718.8		642.8
Creditors: amounts falling due within one year	38	(166.6	)	(135.7	)
Net current assets		552.2		507.1
Net assets		5,298.6		5,253.4
Called up share capital	39	924.5		923.8
Share premium	39	3,739.7		3,733.8
Capital redemption reserve	39	18.3		18.3
Profit and loss account	39	616.1		577.5
Shareholders’ funds	39	5,298.6		5,253.4
Approved by the Board on 3 May 2001 and signed on its behalf by

Charles Miller Smith Chairman	David Nish Finance Director

The Accounting Policies and Definitions, together with Notes 1 to 40 form part of these accounts.

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Notes to the Company Balance Sheet as at 31 March 2001

36 Fixed asset investments
	Subsidiary		Own shares
	undertakings		held under
	Shares	Loans	trust		Total
	£m	£m	£m		£m
Cost or valuation:
At 1 April 2000	1,663.5	3,049.9	32.9		4,746.3
Additions	3.6	–	3.8		7.4
Disposals and other	–	–	(7.3	)	(7.3	)
At 31 March 2001	1,667.1	3,049.9	29.4		4,746.4

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Notes to the Company Balance Sheet as at 31 March 2001

37 Debtors
	2001	2000
	£m	£m
Amounts falling due within one year:
Loans to subsidiary undertakings	633.8	572.5
Interest due from subsidiary undertakings	85.0	70.3
	718.8	642.8

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Notes to the Company Balance Sheet as at 31 March 2001

38 Creditors
	2001	2000
	£m	£m
Amounts falling due within one year:
Corporation tax	31.7	5.3
Accrued expenses	15.5	17.0
Proposed dividend	119.4	113.4
	166.6	135.7

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Notes to the Company Balance Sheet as at 31 March 2001

39 Analysis of movements in share capital and reserves
				Capital	Profit
	Number	Share	Share	redemption	and loss
	of shares	capital	premium	reserve	account	Total
	000s	£m	£m	£m	£m	£m
At 1 April 2000	1,847,586	923.8	3,733.8	18.3	577.5	5,253.4
Retained profit for the year	–	–	–	–	35.0	35.0
Share capital issued
– Employee sharesave scheme	304	0.1	1.4	–	3.6	5.1
– Executive share option scheme	122	0.1	0.1	–	–	0.2
– ESOP	1,014	0.5	4.4	–	–	4.9
At 31 March 2001	1,849,026	924.5	3,739.7	18.3	616.1	5,298.6

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Notes to the Company Balance Sheet as at 31 March 2001

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 3 May 2001. The profit for the financial year per the Accounts of the company was £512.3 million (2000 £1,144.4 million).

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Principal Subsidiary Undertakings and Other Investments

Subsidiary undertakings		Proportion
	Class of share	of shares
	capital	held		Activity
CRE Energy Limited	Ordinary shares £1	100	%	Wind-powered electricity generation
Domestic Appliance Insurance Limited (Isle of Man)	Ordinary shares £1	100	%	Insurance
Manweb plc	Ordinary shares 50p	100	%	Regional electricity company
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 (USA)	Common stock	100	%	Investment holding
Scottish Power UK plc**	Ordinary shares 50p	100	%	Generation, transmission, distribution and supply of electricity and gas supply
ScottishPower Insurance Limited (Isle of Man)	Ordinary shares £1	100	%	Insurance
Southern Water Services Finance plc	Ordinary shares £1	100	%	Finance company
Southern Water Services Limited	Ordinary shares £1	100	%	Water supply and wastewater services
Thus plc	Ordinary shares 2.5p	50.1	%	Internet and telecommunications
Fixed asset investments
Joint ventures
CeltPower Limited	Ordinary shares £1	50	%	Wind-powered electricity generation
ScotAsh Limited	Ordinary shares £1	50	%	Ash sales
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 * 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. 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.

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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 Account , the Group Balance Sheet , the Group Cash Flow Statement , the Statement of Total Recognised Gains and Losses , the Company Balance Sheet and the related notes including the disclosures in respect of directors' remuneration contained in Note 3 (c).

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 2001 and of the profit 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 2001 and 31 March 2000, and the results of its operations and its cash flows for the years ended 31 March 2001, 31 March 2000 and 31 March 1999 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 income, shareholders' equity and cash flows is shown in Note 35 to the Accounts.

PricewaterhouseCoopers
Chartered Accountants and Registered Auditors

Glasgow
3 May 2001

a) The work carried out by the auditors does not involve consideration of the maintenance and integrity of the Scottish Power plc website and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the Annual Report & Accounts/Form 20-F since it was initially presented on the website.

b) Legislation in the United Kingdom governing the preparation and dissemination of financial information may differ from legislation in other jurisdictions.

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Five Year Summary

		Years ended 31 March
		2001		2001		2000		1999		1998		1997
	Notes	$m		£m		£m		£m		£m		£m
UK GAAP Information
Profit and Loss Account Information:
Turnover	(a)	9,016		6,349		4,115		3,242		3,128		2,941
Operating profit	(a)	1,025		722		662		803		785		664
Operating profit (as adjusted)	(a),(b)	1,377		970		961		804		785		685
Profit before taxation		540		380		1,149		644		640		558
Profit before taxation (as adjusted)	(b)	892		628		736		645		640		579
Profit after ordinary taxation		405		285		886		469		460		367
Profit for financial year	(c)	437		308		885		469		142		366
Dividends		(677	)	(477	)	(341	)	(268	)	(243	)	(218	)
Balance Sheet Information:
Total assets		24,106		16,976		15,516		6,232		5,577		4,848
Capital expenditure (net)	(d)	1,556		1,096		887		754		657		471
Long-term liabilities		11,066		7,793		6,895		2,852		2,145		1,758
Net debt		7,505		5,285		4,842		2,421		1,953		1,790
Equity shareholders’ funds		8,368		5,893		5,563		1,203		998		841
Net assets		8,774		6,179		5,863		1,204		1,000		841
Basic weighted average share capital (number of shares, million)		1,830		1,830		1,390		1,185		1,180		1,105
Diluted weighted average share capital (number of shares, million)		1,837		1,837		1,399		1,197		1,192		1,116
Ratios and statistics:
Earnings per ordinary share		$0.2386		16.80	p	63.69	p	39.60	p	12.03	p	33.17	p
Earnings per ordinary share (as adjusted)	(f)	$0.3956		27.86	p	37.97	p	39.70	p	38.90	p	34.94	p
Diluted earnings per ordinary share		$0.2377		16.74	p	63.25	p	39.20	p	11.91	p	32.84	p
Earnings per ScottishPower ADS	(e)	$0.95		£0.67		£2.55		£1.58		£0.48		£1.33
Earnings per ScottishPower ADS (as adjusted)	(e),(f)	$1.58		£1.11		£1.52		£1.59		£1.56		£1.40
Diluted earnings per ADS	(e)	$0.95		£0.67		£2.53		£1.57		£0.48		£1.31
Dividend per ScottishPower ordinary share		$0.3698		26.04	p	24.80	p	22.50	p	20.40p		18.50	p
Dividends per ScottishPower ADS	(e)	$1.48		£1.04		£0.99		£0.90		£0.82		£0.74
Dividend cover (as adjusted)	(f)	1.1	x	1.1	x	1.5	x	1.8	x	1.9	x	1.9	x
Interest cover (as adjusted)	(f)	3.0	x	3.0	x	4.2	x	5.0	x	5.3	x	6.4	x
Gearing	(g)	90	%	90	%	87	%	201	%	196	%	213	%
US GAAP Information
Turnover		9,016		6,349		4,115		3,242		3,128		2,941
Profit for the financial year	(c)	550		387		870		451		126		351
Earnings per ordinary share	(h)	$0.3000		21.13	p	62.59	p	38.08	p	10.70	p	31.72	p
Diluted earnings per ordinary share		$0.2989		21.05	p	62.16	p	37.70	p	10.59	p	31.41	p
Earnings per ScottishPower ADS	(e),(h)	$1.21		£0.85		£2.50		£1.52		£0.43		£1.27
Diluted earnings per ADS	(e)	$1.20		£0.84		£2.49		£1.51		£0.42		£1.26
Total assets		26,477		18,646		16,971		7,344		6,695		6,211
Equity shareholders’ funds under US GAAP		10,597		7,463		7,001		2,457		2,249		2,338
Prior year figures have been restated for the change in accounting policy in 2001 relating to deferred tax following implementation of FRS 19.

(a)	The results for the financial year ended 31 March 1997 included turnover of £316.2 million, operating profit of £114.4 million and operating profit, before exceptional reorganisation costs, of £135.6 million in respect of Southern Water for the period of the year following its acquisition on 6 August 1996. 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)	Earnings and dividends per ScottishPower ADS have been calculated based on a ratio of four ScottishPower ordinary shares to one ScottishPower ADS.
(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, 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, earnings per share have been presented based on US GAAP earnings, without adjustments for the impact of exceptional items, other than those which are classified as extraordinary items under US GAAP, goodwill amortisation and windfall tax. Such additional measures of underlying performance are not permitted under US GAAP. The inclusion of exceptional items, other than those which are classified as extraordinary items under US GAAP, in the determination of earnings per share in accordance with US GAAP increased earnings by £408.9 million or 29.43 pence per share/£1.18 per ADS for the year ended 31 March 2000. The inclusion of goodwill amortisation decreased earnings by £163.5 million or 8.93 pence per share/£0.36 per ADS for the year ended 31 March 2001, by £74.8 million or 5.38 pence per share/£0.22 per ADS for the year ended 31 March 2000, by £34.9 million or 2.94 pence per share/£0.12 per ADS for the year ended 31 March 1999, by £33.5 million or 2.84 pence per share/£0.11 per ADS for the year ended 31 March 1998 and by £26.2 million or 2.37 pence per share/£0.09 per ADS for the year ended 31 March 1997. The inclusion of windfall tax decreased earnings by £317.0 million or 26.86 pence per share/£1.07 per ADS for the year ended 31 March 1998.
(i)	Amounts for the financial year ended 31 March 2001 have been translated, solely for the convenience of the reader, at $1.42 to £1.00, the closing exchange rate on 31 March 2001.

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Glossary of Financial Terms and US Equivalents

Financial Term used in UK Annual Report	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
Profit for financial year	Net 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

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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 The Morgan Guaranty Trust Company of New York, 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 32 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 32 – Historical Share Prices
Period		Ordinary Shares1		American Depositary Shares2
		High (p)	Low (p)	High ($)	Low ($)
1996-97		400.50	300.50	24.52	18.63
1997-98		582.00	352.00	38.74	23.18
1998-99		675.00	521.00	44.63	34.13
1999-00
First quarter		575.50	508.50	36.55	32.68
Second quarter		601.50	518.00	39.06	33.62
Third quarter		595.00	458.50	39.11	29.66
Fourth quarter		528.50	359.50	33.55	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
October 2000		536.00	516.00	31.25	29.81
November 2000		567.00	523.00	32.13	29.38
December 2000		529.00	483.50	30.38	28.00
January 2001		524.00	422.00	31.44	25.06
February 2001		498.00	463.50	28.60	26.78
March 2001		491.00	462.00	28.61	26.22
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.

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Investor Information

On 31 March 2001, there were 495 registered holders of 317,295 ordinary shares with addresses in the US and 58,644 registered holders of 80,585,522 ADSs (equivalent to 322,342,088 ordinary shares). The combined holdings of these shareholders represented 17.43% of the total number of ordinary shares outstanding as at 31 March 2001. UK registered shareholders represented 82.34% of the total number of ordinary shareholders, and all shareholders other than those registered in the UK or the US represented 0.23% of the total number of ordinary shareholders outstanding as at 31 March 2001. 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 33– Analysis of Ordinary Shareholdings at 31 March 2001
Range of holdings	No. of shareholdings	No. of shares
1-100	18,269	777,135
101-200	210,031	35,110,054
201-600	175,875	54,992,505
601-1,000	42,180	33,001,960
1,001-5,000	50,191	91,897,709
5,001-100,000	4,017	64,029,575
100,001 and above	790	1,569,216,854
Total	501,353	1,849,025,792

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Investor Information

Share Capital and Options
As a result of the exercise of options under the employee Sharesave and Executive Share Option Schemes and the issue of shares to the Trustee of the Employee Share Ownership Plan, a total of 1,439,855 ordinary shares of 50p each were issued during the year. Accordingly, the number of ordinary shares in issue was 1,849,025,792 as at 31 March 2001. During the year, 2,458,622 options over ordinary shares were granted to 3,998 employees under the ScottishPower Sharesave Scheme. 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 807,694 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 2001, options were granted to two employees under the PacifiCorp Stock Incentive Plan over a total of 456,600 ordinary shares.

Between 31 March 2001 and 3 May 2001, a further 280,102 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 company last year, shareholders granted authority to the directors to purchase up to 184,761,911 ordinary shares. The directors have not exercised this authority.

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Investor Information

Substantial Shareholdings
As at 3 May 2001, the company had been notified that the following companies were substantial shareholders:

Putnam Investment Management	4.41%
CGNU	3.71%
Prudential plc	3.14%

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 3 May 2001, no person known to the company owned more than 5% of any class of the group's voting securities.

As at 3 May 2001, the total amount of voting securities owned by directors and executive officers of ScottishPower as a group is shown in Table 34.

Table 34 – Voting Securities
Title of Class Identity of Group	Amount Owned	Percentage of Class
Ordinary shares Directors and officers (22 persons)	633,626	0.03%

Full details of the directors' interests in ScottishPower shares are shown in Tables 30 and 31 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 3 May 2001, the directors and officers of the company, as a group, held options to purchase 1,466,563 ordinary shares, all of which were issued pursuant to the Long Term Incentive Plan, Executive Share Option Scheme, ScottishPower's Sharesave Schemes 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.

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Investor Information

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 2001 of £1.00 = $1.42. On 3 May 2001, the Noon Buying Rate was $1.43 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 35 sets out, for the periods indicated, certain information concerning the Noon Buying Rate for US dollars per £1.00.

Table 35 – Historical Exchange Rates
Period		High	Low	Average1	Year end
1996-97		$1.71	$1.49	$1.60	$1.64
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
October 2000		$1.47	$1.43	$1.45
November 2000		$1.45	$1.40	$1.43
December 2000		$1.50	$1.44	$1.46
January 2001		$1.50	$1.46	$1.48
February 2001		$1.48	$1.44	$1.45
March 2001		$1.47	$1.42	$1.44
Note:
	The average of the Noon Buying Rates on the last day of each month during the relevant period.

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Investor Information

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 6.51 pence per share on the ordinary shares will be paid on 15 June 2001 to shareholders on the register on 18 May 2001. This dividend will also be paid to ADS holders on 15 June 2001. This makes total dividends for the year of 26.04 pence per share.

Future dividends will be dependent upon the group's earnings, financial condition and other factors. Dividends paid in the past are not necessarily indicative of future dividends.

The company's stated dividend aim is to achieve 5% nominal growth for each year through to March 2003.

Table 36 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".

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Investors Information

Table 36 – Historical Dividend Payments
		Financial Years
	Notes	2000–01	1999–00	1998–99	1997–98	1996–97
Pence per ordinary share	1
Interim		–	8.27p	7.50p	6.80p	6.17p
Pre–completion		–	8.10p	–	–	–
Quarter (29 Nov 1999 – 31 Dec 1999)		–	2.23p	–	–	–
Quarter (1 Jan 2000 – 31 Mar 2000)		–	6.20p	–	–	–
Quarter (1 April – 30 June)		6.51p	–	–	–	–
Quarter (1 July – 30 Sept)		6.51p	–	–	–	–
Quarter (1 Oct – 31 Dec)		6.51p	–	–	–	–
Quarter (1 Jan – 31 Mar )		6.51p	–	–	–	–
Final		–	–	15.00p	13.60p	12.33p
Total		26.04p	24.80p	22.50p	20.40p	18.50p
US dollars per ADS	1,2
Interim		–	$0.5324	$0.48	$0.46	$0.40
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)		$0.3928	–	–	–	–
Quarter (1 July – 30 Sept)		$0.3702	–	–	–	–
Quarter (1 Oct – 31 Dec)		$0.3805	–	–	–	–
Quarter (1 Jan – 31 Mar)		$0.3721	–	–	–	–
Final		–	–	$0.97	$0.91	$0.81
Total		$1.5156	$1.5808	$1.45	$1.37	$1.21

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.

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Investor Information

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 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. The US and the UK have entered into negotiations to update the current convention between the two countries for the avoidance of double taxation with respect to taxes on income and capital gains ("Income Tax Convention"). The company believes, and the discussion therefore assumes, that it is 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 of 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 effectively connected with 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.

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Investor Information

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 includes 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, as discussed below, 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 procedures for 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.

An Eligible 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 dividend income, an Eligible 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. Individual Eligible US Holders, however, 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 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 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 taxes 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.

• UK Menu     • Cross Reference to Form 20-F (US)

Investor Information

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 Eligible US Holder's holding period for such ordinary shares or ADSs exceeds one year. Any such gain and 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 paid to them during the year. "Backup withholding" at the rate of 31% 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 Menu     • Cross Reference to Form 20-F (US)

Investor Information

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
No UK stamp duty will be payable 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.

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 nomine 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.

• UK Menu     • Cross Reference to Form 20-F (US)

Financial Calendar

	Looking Ahead
15 June 2001	Dividend payment date – US and UK (final dividend for the year ended 31 March 2001)
27 July 2001	Annual General Meeting
August 2001	Announcement of results for quarter ending 30 June 2001 – Q1
August 2001	Shares ex-dividend
September 2001	Q1 Dividend payable
November 2001	Announcement of results for quarter ending 30 September 2001 – Q2
November 2001	Shares ex-dividend
December 2001	Q2 Dividend payable
February 2002	Announcement of results for quarter ending 31 December 2001 – Q3
February 2002	Shares ex-dividend
March 2002	Q3 Dividend payable
May 2002	Announcement of Preliminary Results for the year ending 31 March 2002
May 2002	Shares ex-dividend
June 2002	Q4 Dividend payable (final dividend for the year ending 31 March 2002)

Annual General Meeting
The Annual General Meeting will be held at The Glasgow Royal Concert Hall, Sauchiehall Street, Glasgow, on Friday 27 July 2001 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 2001, 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 and Community Reports may be obtained, free of charge, on request from the Company Secretary at the company's registered office. The Corporate Environment and Community Reports are also 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 2000-01 is also available on audio tape, free of charge, from the Company's Secretary at the company's registered office.

   

• UK Menu     • Cross Reference to Form 20-F (US)

 Shareholder Services

Ordinary Shares

Share Registration Enquiries

The Registrar
Lloyds TSB Registrars Scotland
117 Dundas Street
Edinburgh EH3 5ED

Tel: +44 (0)870 600 3999
Fax: +44 (0)870 900 0030
Textphone: +44 (0)870 600 3950

Dividend Reinvestment Plan
ScottishPower introduced a Dividend Reinvestment Plan in September 2000. 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

Morgan Guaranty Trust Company of New York
Shareholder Relations
PO Box 842006
Boston, MA 02284-2006

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

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 Morgan Guaranty Trust Company of New York 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

• UK Menu     • Cross Reference to Form 20-F (US)

Glossary of Terms

Term – Definition

ADS – American Depositary Share (US)

Authority – The Gas and Electricity Markets Authority, the body which determines energy market regulation in Great Britain (UK)

BETTA – British Electricity Trading and Transmission Arrangements (UK)

BPA – Bonneville Power Administration (US)

Billion – One thousand million (1,000,000,000)

CCGT – Combined-cycle gas turbine

CO2 – Carbon Dioxide

Company – Scottish Power plc

DGES – Director General of Electricity Supply (UK)

DGGS – Director General of Gas Supply (UK)

DGWS – Director General of Water Services (UK)

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)

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)

ESI – The electricity supply industry in Great Britain (UK)

ESOP – Employee Share Ownership Plan (UK)

FERC – Federal Energy Regulatory Commission (US)

FGD – Flue Gas Desulphurisation

First-tier – Public electricity supply within a company's home area (UK)

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 PES was previously the sole licensed supplier of residential customers (UK)

Interconnector – The high voltage link connecting the transmission system of Scotland with that of England & Wales (UK)

ISA – Individual Savings Account (UK)

ISP – Internet Service Provider

Kilo (k) – One thousand (1,000) units

LTIP – Long–Term Incentive Plan

Mega (M) – One million (1,000,000) units

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)

PES – Public Electricity Supplier (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)

RPI – Retail Price Index, the equivalent of the US Consumer Price Index – CPI (UK)

SEC – Securities and Exchange Commission (US)

Second-tier – Public electricity supply outside a company's home area (UK)

SEPA – Scottish Environment Protection Agency (UK)

Sewage – Wastewater contained in or being discharged from sewerage (UK)

Sewerage – Wastewater infrastructure assets (UK)

SO2 – Sulphur Dioxide

Transmission – The transfer of electricity from power stations to the distribution system

UK – United Kingdom, comprising England, Scotland, Wales and Northern Ireland

US – United States of America

UWWTD – Urban Waste Water Treatment Directive (UK)

Volt (V) – Unit of electrical potential

WaSC – Water and Sewerage Company (UK)

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

Wholesale – The dealing of bulk power with another power supplier

WSCC – Western System Coordinating Council (US)

WTW – Wastewater Treatment Works (UK)

(US) or (UK) in the definitions above indicates that the term is applicable to the United States or the United Kingdom, respectively.

Conversion Factors	Metres		Yards
	0.91	1	1.09
	Km		Miles
	1.61	1	0.62
	Litres		US Gallons
	3.78	1	0.26

• UK Menu     • Cross Reference to Form 20-F (US)