Edgar Filing: SCOTTISH POWER PLC

Form 6-K

SECURITIES AND EXCHANGE COMMISSIONS

WASHINGTON, DC 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a-16 OR 15a-16 OF

THE SECURITIES EXCHANGE ACT OF 1934

For the month of June 2006

SCOTTISH POWER PLC

(Translation of Registrant’s Name Into English)

CORPORATE OFFICE, 1 ATLANTIC QUAY, GLASGOW, G2 8SP

(Address of Principal Executive Offices)

(Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.) Form 20-F x Form 40-F ¨

(Indicate by check mark whether the registrant by furnishing the information contained in this form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.) Yes ¨ No x

(If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82- .)

FORM 6-K: TABLE OF CONTENTS

1. Annual Report for the year ended March 31, 2006.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


			/s/ Scottish Power plc (Registrant)

Date	June 16, 2006	By:	/s/ Donald McPherson
			Donald McPherson Assistant Secretary

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ScottishPower

Annual Report & Accounts 2005/06

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Financial Highlights

2006 2005

Revenue (from continuing operations) £5,446m £4,595m

Operating profit (from continuing operations) £870m £673m

Adjusted operating profit (from continuing operations) £805m £580m

Profit before tax (from continuing operations) £625m £552m

Adjusted profit before tax (from continuing operations) £675m £459m

Group earnings/(loss) per share 83.77p (10.56)p

Group adjusted earnings per share 44.13p 36.24p

Dividends per share 25.00p 22.50p

OPERATING PROFIT FROM CONTINUING OPERATIONS (£m)

£870m

ADJUSTED OPERATING PROFIT FROM CONTINUING OPERATIONS (£m)

£805m

GROUP EARNINGS/(LOSS) PER SHARE (p)

83.8p

GROUP ADJUSTED EARNINGS PER SHARE (p)

44.1p

470

486

573

673

870

494

491

569

580

805

02†

26.2

29.4

83.8

26.1

33.7

36.4

36.2

44.1

02† 03† 04† 05•* 06•

05•*

03† 04†

(10.6)

06•

02† 03† 04† 05•* 06•

(53.7)

TOTAL SHAREHOLDER RETURN (p)

74.45p

Capital appreciation plus dividend reinvestment for £1 invested on 1 April 2001

Source: Datastream

3.54

17.16

74.45

(15.88)

(4.20)

CHANGE IN TOTAL

SHAREHOLDER RETURN (%)

48.90%

Percentage change in total shareholder return index in each financial year

Source: Datastream

13.90

8.08

13.15

48.90

27.34

DIVIDENDS PER SHARE (p)

25.00p

§Cash dividends excluding ‘dividends in specie’ on demerger of thus

28.71

20.50

22.50

25.00

02§ 03 04 05 06#

(15.88)

Adjusted operating profit from continuing operations, adjusted profit before tax from continuing operations and group adjusted earnings per share under IFRS have been computed on the basis described on page 9. The adjusted operating profit from continuing operations and group adjusted earnings per share under UK GAAP are stated before goodwill amortisation and exceptional items.

† UK GAAP • IFRS

* The equivalent UK GAAP figures for 2005 were as follows: operating profit from continuing operations of £689 million, adjusted operating profit from continuing operations of £695 million, group loss per share of 16.8 pence and group adjusted earnings per share of 40.2 pence.

# This dividend is the aggregation of the 5.2 pence per share paid in each of the first three quarters of 2005/06 on the ordinary shares in existence prior to the reorganisation of the company’s share capital on 12 May 2006, and the fourth quarter dividend of 9.4 pence per new ordinary share in existence following the reorganisation. The reorganisation is associated with the return of cash to shareholders. The record date for the fourth quarter dividend fell after the record date for the reorganisation. Accordingly, the proposed full year dividend of 25.0 pence is in respect of each ordinary share held on the relevant record dates.

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ScottishPower, a public limited company registered in Scotland, is an international energy business. The group provides electricity transmission and distribution services in the UK; supplies approximately 5.25 million electricity and gas services to homes and businesses across the UK; and operates electricity generation, gas storage facilities and associated energy management activities in the UK, the US and western Canada.

This Annual Report & Accounts examines our performance in 2005/06 and assesses the issues and opportunities ahead.

BLACK LAW WINDFARM, LANARKSHIRE

One of Scotland’s largest windfarms.

CONTENTS

REPORT OF THE DIRECTORS

2 Chairman’s Statement

3 Chief Executive’s Review

6 Business Review

48 Board of Directors and

Executive Team

51 Corporate Governance

57 Remuneration Report of the Directors

69 Safe Harbor Statement

ACCOUNTS 2005/06

70 Accounting Policies and Definitions

84 Group Income Statement

85 Group Statement of Recognised Income and Expense

86 Group Cash Flow Statement

88 Group Balance Sheet

89 Notes to the Group Accounts

156 Independent Auditors’ Report on the Group Accounts

157 Selected Financial Data Company Balance Sheet

163 Notes to the Company Balance Sheet

167 Independent Auditors’ Report on the Company Accounts

INVESTOR INFORMATION

168 Investor Information

174 Financial Calendar

175 Shareholder Services

INDEX

GLOSSARY OF TERMS

ScottishPower Annual Report & Accounts 2005/06 1

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Chairman’s Statement

Read more at www.scottishpower.com

“This is an excellent set of results for ScottishPower. All our businesses have delivered very good growth through improved operational performance and attractive returns on our investment programme.”

CONTINUING OPERATIONS

adjusted operating profit £805m* (up 39%); adjusted profit before tax £675m* (up 47%); adjusted earnings per share 27.9p* (up 46%).

£805m*

TOTAL GROUP ADJUSTED EARNINGS PER SHARE 44.1p* (up 22%); reported earnings per share 83.8p (2004/05: 10.6p loss per share).

CASH GENERATED from continuing operations increased by £183m to £864m.

£864m

PHILIP BOWMAN

SCOTTISHPOWER has performed strongly throughout the year with adjusted operating profit up by 39% to £805 million*; adjusted profit before tax up by 47% to £675 million* and adjusted earnings per share up 46% to 27.9 pence* for our continuing operations. Cash generated from continuing operations increased by £183 million to £864 million. All of our businesses contributed to this strong performance. Energy Networks has invested £282 million to expand and improve its infrastructure assets, and has delivered an 11% improvement in network performance. Energy Retail & Wholesale reaped the benefits of recent investments in generation plant capacity and flexibility, and of its commodity procurement strategy, to deliver strong profit growth in the face of sharply rising commodity costs. Energy Wholesale also made substantial progress in its wind development programme, with the construction of phase one of Black Law windfarm completed and planning approval granted for Europe’s largest on-shore windfarm at Whitelee. Reflecting the business strategy of focusing on profitable customer growth, Energy Retail slowed its rate of customer growth during a year of high and rising wholesale prices, growing its customer base by 136,000 to 5.25 million at March 2006. Energy Retail drove further improvements in efficiencies and customer service through initiatives such as its award-winning 6 Sigma programme, resulting in improvements in billing accuracy, first call resolution and direct debit penetration amongst our retail domestic customers. In addition to the continued development of its wind business, PPM Energy demonstrated the strength of its owned and contracted gas storage businesses, which delivered strong profit growth on the back of volatile North American gas prices, and further expanded its energy management and origination activities into profitable new markets.

Capital investment during the year of £1 billion was driven by our windfarm development programme in the UK and US and renewal and reinforcement of our generation and network assets in the UK. Returns from our investment programme are Items marked * represent adjusted results, further details of which, together with the reported results, are given in the ‘Business Review’ section on page 9.

ScottishPower Annual Report & Accounts 2005/06 3

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Chief Executive’s review

£1.7billion

ENERGY NETWORKS INVESTMENT

to 2010 will amount to some £1.7 billion

£1.5 billion

ENERGY RETAIL & WHOLESALE

INVESTMENT of some £1.5 billion to 2010

£1.6 billion

PPM ENERGY INVESTMENT

to 2010 will amount to £1.6 billion

well ahead of our cost of capital and are evident in the strong operating profit performance of each of our businesses. Refurbishment of our network assets and overhaul of our generation plant accounted for half of our UK capital investment during the year. In the US, PPM Energy successfully completed its 574 MW windfarm construction programme, more than tripling its owned capacity and firmly establishing it as one of North America’s leading renewables businesses. In the UK, Energy Wholesale added 130 MW of new wind generation, bringing its operational capacity to 288 MW, making it the leading on-shore wind developer in the UK. With final planning approval granted for Europe’s largest on-shore windfarm at Whitelee, ScottishPower now has a further 490 MW under construction or in receipt of planning approvals. In April 2006, we received the Queen’s Award for Enterprise for our collaborative and responsible approach to windfarm development.

PacifiCorp was sold to MidAmerican in March well ahead of the original schedule. The sale will enable us to return £2.25 billion of cash to shareholders, substantially repair the deficit in our pension schemes and begin a new phase in ScottishPower’s development.

ScottishPower has a strong set of businesses; each well positioned in its market and well placed for future growth and investment. As a result, we have increased our investment programme by £1.3 billion to £4.8 billion for the period to 2010, with the increased investment targeted at further reinforcement and renewables infrastructure in Energy Networks, Longannet Flue Gas Desulphurisation (“FGD”) and life extension, and additional windfarm developments in PPM Energy. We will continue to deliver value for our shareholders by driving continued improvement in operational performance, investing for organic growth, and increasing the focus on cash generation.

In Energy Networks we plan to deliver returns at, or in excess of, the level of allowed cost of capital on our expanding regulated asset base, through continued improvement in our asset and operational management. Securing a fair outcome from the Transmission Price Control Review, with sufficient and timely funding for the required increase in capital investment, will be a key priority for the coming year. Investment to 2010 will amount to some £1.7 billion, and includes expenditure to improve security of supply and network performance and facilitate the connection of renewables.

In Energy Retail & Wholesale we will focus on improving customer service and operating margins, and will seek further growth in our customer base only where it is profitable to do so. Growth and margins will be supported by our flexible and diverse generation portfolio, successful forward commodity procurement strategy, and our policy of setting retail tariffs to reflect underlying energy costs and use of system charges. Investment of some £1.5 billion to 2010 will include further plant performance upgrades, additional windfarm development to meet our renewable targets, and the installation of FGD equipment and life extension initiatives at the 2,304 MW Longannet power station, securing its contribution to the UK’s energy supply needs.

In PPM Energy we will continue to build leading positions in wind generation and independent gas storage, and expand our energy management and origination businesses. Investment totalling some £1.6 billion to 2010 will include new windfarm and gas storage projects. We have approved plans to build 857 MW of new windpower in the 2006 and 2007 calendar years to add to our existing portfolio of 1,405 MW. In May, we completed our first wind portfolio financing structure through which we will realise the value of the wind tax benefits. The strength of our renewable project pipeline and our confidence in prospective returns, has allowed us to increase our 2010 target by over 50% to at least 3,500 MW developed or controlled by PPM Energy.

We continue to engage with the UK Government on the policy issues raised by the Energy Review. The UK needs a diverse generation portfolio and expanded infrastructure to deliver greater security of supply at competitive cost while helping to meet national carbon reduction targets. The development of a clear and consistent framework for energy policy is essential to attract future investment. We have emphasised, in particular, the need for consistency in the implementation of the Renewables Obligation (“RO”) and the EU Emissions Trading Scheme (“ETS”). Our experience as the leading on-shore developer of windpower in the UK bears out our view that the RO is a

ScottishPower Annual Report & Accounts 2005/06

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successful mechanism for securing investment in windpower and other renewable technologies. It should be retained in its current form. We have pressed for action to address the planning and network constraints that continue to be obstacles to renewables development. Our investment in FGD at Longannet is a significant step towards securing the UK’s future energy supply needs. We are seeking clarity in the implementation of Phase II of the EU ETS, consistent with the DTI’s December 2005 benchmarking proposals, and the early development of arrangements for Phase III and beyond.

Health and safety of our employees continues to be a high priority and our efforts to promote a higher level of safety culture and awareness have been reflected in an increased level of performance in this area and a reduced number of accidents. During the year there were 29 Lost Time Accidents and no fatalities—an improvement of 22% year-on-year in the number of Lost Time Accidents. Through leadership our objective is to instil safety as an integral part of the ScottishPower culture and minimise harm to employees, contractors and members of the public from our equipment and working practices. In support of this we have increased health and safety training for managers and team leaders across the group to generate the necessary leadership skills. We have also developed our risk assessment methods and continue to play an active role in safety awareness initiatives at locations across our franchise areas.

Our approach to Corporate Responsibility continued to evolve during the year, influenced by a reassessment of our business as we approached the sale of PacifiCorp and a review of stakeholder expectations. Our next report will be substantially changed in format and will measure our impact on society and environment against 12 performance criteria. It will be available for viewing, or download, on our corporate website by early autumn 2006.

CONCLUSION Evolving energy policy in an environment of rising and volatile energy prices creates challenges and opportunities for ScottishPower. As a leading player in power generation, energy retail and network infrastructure in the UK and in high-value, fast-growing segments of the US market, we are well positioned. We have strong businesses, with attractive investment plans, and the ability and agility to respond to challenges and new opportunities. With our clearly defined strategy for investment and growth we are focused on implementing plans that provide attractive returns, delivering further operational efficiencies and building a culture of operational excellence across the organisation. I am confident that ScottishPower will deliver growth and value for shareholders.

ScottishPower Annual Report & Accounts 2005/06 5

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Business Review

Group Overview

1.1. Activities 1.2. Strategy 1.3. Group Structure 1.4. Key Business Drivers

Dividend & Dividend Policy

Group Financial Review of the Year to 31 March 2006

3.1. Group Income Statement 3.2. Cash Flow and Net Debt 3.3. Investment 3.4. Group Balance Sheet 3.5. Significant Changes 3.6. Future Trends

Continuing Operations

4.1. Energy Networks

4.2. Energy Retail & Wholesale 4.3. PPM Energy 4.4. Unallocated Activities

Discontinued Operations – PacifiCorp

Capital Structure, Treasury Policies & Liquidity

6.1. Capital Structure

6.2. Treasury Policies & Liquidity 6.3. Going Concern

Fair Value of Derivative Contracts, Pension

& Off Balance Sheet Arrangements

7.1. Fair Value of Derivative Contracts 7.2. Pension Arrangements 7.3. Off Balance Sheet Arrangements

IFRS to US GAAP Reconciliation

9 Resources, Relationships & Risk Factors

9.1. Resources 9.2. Relationships 9.3. Risk Factors

10 Critical Accounting Policies & Accounting Developments

10.1. Critical Accounting Policies – IFRS 10.2. Critical Accounting Policies – US GAAP 10.3. Accounting Developments

11 Cautionary Statement Regarding Non-GAAP Financial Information

Group Overview

1.1 ACTIVITIES

Scottish Power plc (“ScottishPower”), a public limited company registered in Scotland, is an international energy business and had continuing operations revenue of £5.4 billion, reported operating profit of £870 million and reported profit before tax of £625 million in 2005/06. Through its continuing businesses, the company provides electricity transmission and distribution services in the UK; supplies 5.25 million (2004/05: 5.12 million) electricity and gas services to homes and businesses across the UK; and operates electricity generation, gas storage facilities and associated energy management activities in the UK, Ireland, the US and western Canada.

ScottishPower was created upon privatisation in 1991 and then developed by both organic growth and strategic acquisitions in the British electricity, gas, water and telephony markets and through its November 1999 acquisition of PacifiCorp in the US. Since the group’s redefinition as an energy business in 2001, it has focused on investing for growth and improving operational performance in its energy businesses. Following a strategic review of PacifiCorp, the ScottishPower Board concluded in May 2005 that shareholders’ interests were best served by a sale of PacifiCorp and a return of cash to shareholders.

The sale of PacifiCorp to MidAmerican Energy Holdings Company (“MidAmerican”) was completed on 21 March 2006. Shareholder approval for the return of approximately £2.25 billion of the net cash proceeds from the sale of PacifiCorp was received on 4 May 2006. This return of cash is being implemented by way of a B share structure, which gave shareholders a choice as to whether they receive their cash in the form of income or capital, and further choice as to the timing of capital receipt. Under the terms of the capital reorganisation, implemented in conjunction with the return of cash, existing ordinary shares were subdivided and consolidated. The intention of the capital reorganisation was that, subject to market movements, the share price of one new ordinary share, immediately after listing of the new ordinary share, should be approximately equal to the share price of one existing ordinary share, immediately beforehand.

1.2 STRATEGY

ScottishPower’s strategy is to be the UK’s best integrated energy provider and a world leader in renewables.

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

ScottishPower Annual Report & Accounts 2005/06

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It will continue to maximise the effectiveness and efficiency of its core businesses through strong operational management, investing to renew and revitalise assets in the UK, as well as growing through major organic investment both in the UK, and in North America through its PPM Energy business.

1.3 GROUP STRUCTURE

Throughout 2005/06, the group operated through its continuing businesses:

Energy Networks (formerly Infrastructure Division) Energy Retail & Wholesale (formerly UK Division) PPM Energy

The group accounted for PacifiCorp as a discontinued operation during 2005/06, the sale of PacifiCorp to MidAmerican having completed on 21 March 2006.

A corporate restructuring, announced in September 2005, reduced layers of management and consolidated shared support functions in the UK. A range of initiatives to simplify and standardise business processes, many of the changes representing the cessation of activities related to the ownership of PacifiCorp, is expected to come into effect over the balance of 2006/07.

1.3.1 GEOGRAPHICAL STRUCTURE

In the UK, Energy Networks manages the electricity transmission and distribution subsidiaries of the wholly-owned UK holding company Scottish Power UK plc (“SPUK”). Other subsidiaries comprise the group’s competitive energy businesses, Energy Wholesale, covering its generation assets in the British Isles, its commercial and energy management activities; and Energy Retail, managing its energy supply business units. The group’s North American wholesale energy and gas storage business, PPM Energy, Inc. (“PPM Energy”) and Scottish Power Finance (US), Inc. (“SPFUS”), are both subsidiaries of ScottishPower Holdings, Inc. (“SPHI”) (formerly PacifiCorp Holdings, Inc.). SPFUS acts as guarantor for a number of the contracts of PPM Energy, PPM Energy Canada Ltd and other affiliates of PPM Energy. In addition to PPM Energy, the group operates certain non-regulated US subsidiaries, which act as lessor for a small portfolio of assets, comprising principally commercial aircraft, and receive royalty income from the previously disposed Synfuel operation, extending until September 2007.

In financial years 2005/06 and 2004/05, the continuing businesses’ geographical distribution of external revenue and adjusted operating profit was very similar in each case, with approximately 90%* concentrated in the UK and 10%* in the US.

1.3.2 REGULATED AND COMPETITIVE STRUCTURE

The group’s regulated business, Energy Networks, is based in the UK. It accounted for £562 million or 10% of the continuing businesses’ external revenue in the current year (2004/05: £380 million or 8%) and £525 million* or 63% of adjusted operating profit (2004/05: £427 million* or 74%). At operating profit level, Energy Networks is the group’s largest business. Further information on Energy Networks is provided in Section 4.1 below.

The group’s competitive businesses are Energy Retail & Wholesale based in the UK and PPM Energy in the US. Together they contributed £4,873 million or 90% of the continuing businesses’ external revenue in the current year (2004/05: £4,187 million or 92%) and £305 million* or 37% of

SCOTTISHPOWER THE GROUP

SCOTTISH POWER PLC

UK HOLDING COMPANY

US HOLDING COMPANY

ENERGY NETWORKS

SP Distribution Ltd

SP Manweb plc SP Power Systems Ltd SP Transmission Ltd

ENERGY RETAIL & WHOLESALE

ScottishPower Energy

Management Ltd

ScottishPower

Energy Management

(Agency) Ltd ScottishPower Energy

Retail Ltd

ScottishPower

Generation Ltd

SP Dataserve Ltd

PPM ENERGY

PPM Energy, Inc.

ENSTOR, Inc.

Pacific Klamath Energy

PPM Energy

Canada Ltd

PACIFICORP

Discontinued business: Sale completed 21 March 2006

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

ScottishPower Annual Report & Accounts 2005/06 7

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Business Review

EXTERNAL REVENUE FOR CONTINUING BUSINESSES Regulated Energy Networks 10%

Competitive Energy Retail & Wholesale 80%

PPM Energy 10%

Energy Networks Energy Retail & Wholesale PPM Energy

OPERATING PROFIT FOR CONTINUING BUSINESSES

Adjusted* Reported

Regulated Energy Networks 63% 54%

Competitive Energy Retail & Wholesale 26% 40%

PPM Energy 11% 6%

adjusted operating profit (2004/05: £152 million* or 26%). Further information on Energy Retail & Wholesale and PPM Energy is provided in Sections 4.2 and 4.3 below.

1.3.3 SEASONALITY

The group’s recent results, excluding the effect of IAS 39 volatility and exceptional items, have been affected to an extent by seasonality, with group external revenue and adjusted operating profit weighted towards the second half of the year, primarily as a result of higher winter demand in the UK. PPM Energy’s gas storage activities have also impacted the distribution of adjusted operating profit this year, weighting it towards the second half of the year. This was due to market conditions, which may or may not occur in future years.

1.4 KEY BUSINESS DRIVERS

The businesses’ key drivers impacting the financial performance of the group are shown in Table 1.

Other factors affecting financial performance include increases and reductions in customer demand for electricity, economic growth and downturns, and abnormal weather, all of which impact revenues, cash flows and investment. The group proactively manages its supply and demand balance, but any unanticipated changes in future customer demand, weather conditions, generation resource availability or commodity prices may affect revenues from, and the cost of, supplying gas and electricity to customers.

Dividend & Dividend Policy

Following a review of dividend policy, ScottishPower announced a total dividend for the year ended 31 March 2006 of 25.0 pence per ordinary share (2004/05: 22.5 pence), a year-on-year increase of 11.1%. This dividend is the aggregation of the 5.2 pence per share paid in each of the first three quarters of 2005/06 on the ordinary shares in existence prior to the reorganisation of the company’s share capital on 12 May 2006, and the fourth quarter dividend of 9.4 pence per new ordinary share in existence following the reorganisation. The reorganisation is associated with the return of cash to shareholders. The record date for the fourth quarter dividend fell after the record date for the reorganisation. Accordingly, the proposed full year dividend of 25.0 pence is in respect of each ordinary share held on the relevant record dates. For the next two years, ScottishPower is aiming to deliver a minimum annual increase in the dividend of 7% from the 2005/06 base of 25.0 pence per ordinary share.

In light of the completion of the sale of PacifiCorp the Board intends to pay the dividend bi-annually, and, in line with the rest of the group’s UK sector peer group, will also move from reporting results quarterly to bi-annually. The interim dividend for 2006/07 will be 11.4 pence per share, payable in December 2006, with the final dividend payable in June 2007.

TABLE 1

Key drivers

ENERGY NETWORKS

Secure a fair outcome from Transmission Price Control Review

Achieve and outperform Ofgem targets for network performance and efficiencies

Deliver investment plan

ENERGY RETAIL & WHOLESALE

Manage the integrated business for value

Deliver investment plans for short-term plant optimisation and long-term growth

Continue to improve customer service Increase focus on effective debt management PPM ENERGY

Deliver new wind product offerings and financing Progress wind and gas storage developments Extend energy management and origination activities

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

ScottishPower Annual Report & Accounts 2005/06

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The return of cash financed from the $5.1 billion net cash proceeds from the PacifiCorp disposal was implemented through a reclassification of one in three of the company’s existing ordinary shares into B shares. Shareholders were able to elect from three alternatives in respect of the B shares: to receive a single B share dividend; to sell some or all of their B shares under an Initial Repurchase Offer; or to retain their B shares and have the opportunity for them to be repurchased by the company at certain future dates; or a mixture of all three.

Group Financial Review of the Year to 31 March 2006

NON- GAAP FINANCIAL MEASURES

Note: The group’s results have been prepared in accordance with IFRS for the first time for the year ended 31 March 2006. Comparative figures for the previous year have also been restated on this basis. IAS 39 (“Financial Instruments: Recognition and Measurement”) has been applied prospectively with effect from 1 April 2005. As a result, the statutory results for the year ended 31 March 2006 are not directly comparable to the equivalent period last year, largely due to the recognition of fair value gains and losses relating to IAS 39 and due to exceptional items. The main focus of the results is on the continuing businesses. The sale of PacifiCorp was completed on 21 March 2006 and PacifiCorp is reported as a discontinued operation within the group’s results.

Items marked * represent the results of operations adjusted to: (i) exclude the effects of IAS 39 on 2005/06 results; (ii) for 2004/05, exclude the impact on results of contracts which were previously marked to market or otherwise fair valued but are now subject to IAS 39; (iii) exclude exceptional items; and (iv) in relation to PacifiCorp, include depreciation and amortisation charges from 24 May 2005 to 20 March 2006, which under IFRS are not recognised in the group’s reported results. Reconciliations from the reported to the adjusted results are provided in Notes 1 and 10 to the Accounts. As a consequence of these adjustments, the results for both years are presented on a comparable basis. ScottishPower believes that the adjusted measures provide a better comparison of underlying business performance.

In accordance with guidance from the UK Auditing Practices Board, the UK Listing Authority, and the US Securities and Exchange Commission, where non-GAAP figures are discussed, comparable IFRS figures have also been discussed and reconciled to the non-GAAP figures. A detailed ‘Cautionary Statement Regarding Non-GAAP Financial Information’ is provided in Section 11. The full statutory results are presented in the ‘Group Income Statement’ and in Note 1 ‘Segmental income statement information’ on page 84 and on page 89, respectively.

3.1 GROUP INCOME STATEMENT

OVERVIEW

The group’s results for the year ended 31 March 2006 have been prepared in accordance with IFRS for the first time, with prior year comparatives restated on a consistent basis, except for the adoption of IAS 39, which has been applied prospectively from 1 April 2005. The sale of PacifiCorp was completed on 21 March 2006 and each line description of the Group Income Statement now excludes items directly associated with the disposal, as these items are now netted within a separate discontinued operations line for both the current and prior year. The classification of corporate costs has also been reviewed and these are now included within unallocated income and expenses, together with the results of non-regulated US activities which have been retained by the group, and were previously reported within the PacifiCorp business.

The group has delivered strong results for the year with all continuing businesses contributing to this growth. Improved operational performance and success in delivering returns from the organic investment programme resulted in adjusted operating profit for continuing operations increasing by 39% to £805 million*. Reported operating profit for continuing operations increased by 29% to £870 million and included fair value gains on operating derivatives and exceptional items, both of which are discussed below.

The sale of PacifiCorp was achieved significantly ahead of schedule and resulted in a £619 million gain on sale being reported within discontinued operations in the Group Income Statement, primarily associated with cumulative translation (foreign exchange) gains recycled from reserves.

Shareholders approved the £2.25 billion return of cash on 4 May 2006. It is expected that new ordinary share certificates, sales advices and cheques, as appropriate, will be despatched to relevant shareholders or relevant shareholders will have their CREST accounts credited with the proceeds, as appropriate, on 5 June 2006. With respect to ADS holders, cheques and transaction advices are expected to be despatched and book-entry credits, as appropriate, made on or after 12 June 2006.

The corporate restructuring delivered £10 million of savings in 2005/06 and is expected to achieve £50 million of savings in 2006/07, with the full cost savings of £60 million targeted in 2007/08.

External group revenue for the year to 31 March 2006 increased by £851 million to £5,446 million. Energy Network’s revenue increased by £182 million largely due to a combination of a change in billing arrangements under the British Electricity Trading and Transmission Arrangements (“BETTA”) and increased external regulatory income following the recent price control reviews. Energy Retail & Wholesale’s revenue rose by £642 million, reflecting customer number growth, higher-priced wholesale market sales and tariff rises within the retail electricity and gas markets, which were required due to increasing commodity prices. PPM Energy’s revenue increased by £44 million principally due to increased volumes in owned and

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

ScottishPower Annual Report & Accounts 2005/06 9

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Business Review contracted gas storage. Unallocated revenues were £17 million lower largely due to reduced Synfuel royalties.

Cost of sales of £3,966 million increased by £684 million on last year, predominately reflecting increased market prices associated with Energy Wholesale’s gas and electricity purchases. Transmission and distribution costs increased by £34 million to £327 million as a result of higher rates and depreciation, and also due to a one-off gain on the sale of gas assets in the prior year, not repeated. Administrative expenses were £101 million higher than last year at £481 million mainly due to the £101 million exceptional charge which is discussed in detail below. Depreciation and amortisation costs, which are included within each of the three preceding cost categories, reduced by £30 million to £249 million. The reduction was primarily due to the reclassification of intangible assets as derivative financial instruments on implementation of IAS 39 and therefore, there has been a reduction in the amortisation of intangible assets of £34 million, associated with this reclassification.

Adjusted operating profit for continuing operations increased by 39% to £805 million* for the year. This growth was driven by: higher regulatory revenues and effective cost management in Energy Networks; excellent investment returns from the expanded generation and renewables portfolios in both the UK and US; strong energy management activities in Energy Wholesale aligned with the effective management of the Energy Retail customer base; and improved owned and contracted gas storage profits in PPM Energy. Unallocated income and expenses were adverse principally due to reduced Synfuel royalties and higher US net operating costs, partly offset by lower corporate costs. Details of the adjustments made for the year are shown in Table 2.

TABLE 2

Group operating profit (£m)

2005/06 2004/05 Change

Reported operating profit 869.7 673.2 196.5

Adjustments:

IAS 39/contracts now within the scope of IAS 39 (85.3) (93.2) 7.9

Exceptional items 20.1 — 20.1

Adjusted operating profit* 804.5 580.0 224.5

Reported operating profit for continuing operations, which included the impact of IAS 39 and exceptional items, increased by 29% to £870 million for the year.

As shown in Table 2, the adoption of IAS 39 increased operating profit by £85 million in the year. This was as a result of the unwind of opening balance sheet positions of £111 million, offset by mark-to-market losses of £22 million and hedge ineffectiveness of £3 million.

As shown in Table 2, a continuing operations’ net exceptional charge of £20 million pre-tax was recorded, which comprised: an £81 million gain on sale of the underground natural gas storage project at Byley; a £42 million charge relating to the corporate restructuring programme announced in September 2005; within the retained US non-regulated business, a £25 million impairment provision in relation to the historic aircraft lease portfolio, which was inherited with the PacifiCorp acquisition; and, within PPM Energy, a £34 million charge relating to probable

liabilities associated with a credit support facility. This facility was provided by PacifiCorp Holdings Inc. (now SPHI) to certain providers of debt to the Klamath Co-generation project at the project’s inception in 1999. The project is owned by the City of Klamath Falls, but operated by PPM Energy, which has a purchase contract for 47% of the output.

The corporate restructuring delivered savings of £10 million in the second half of 2005/06, with the businesses delivering £4 million of the efficiency savings and support services delivering a further £6 million. To date, there has been a reduction in the number of full-time positions across the group of 517. A further reduction of some 200 full-time positions will occur in 2006/07.

Adjusted net finance costs for continuing operations, as shown in Table 3, increased by £8 million to £129 million* for the year. Reported net finance costs increased by £124 million to £245 million, after £115 million of IAS 39 fair value losses on financing derivatives, primarily reflecting the significant impact the rise in the company’s share price has had on the fair value of the embedded derivative within the $700 million convertible bonds. Interest received on the proceeds from the sale of PacifiCorp was £4 million.

TABLE 3

Net finance costs (£m)

2005/06 2004/05 Change

Reported net finance costs 244.6 120.8 123.8

Adjustments: IAS 39 (115.4) — (115.4)

Adjusted net finance costs* 129.2 120.8 8.4

Adjusted profit before tax for continuing operations, as shown in Table 4, increased by £216 million (47%) to £675 million* for the year. This growth was driven by the continuing businesses’ strong operational results with financing costs marginally higher. Reported profit before tax was £73 million higher at £625 million for the year. The impact of IAS 39 volatility on continuing operations’ reported operating profit and finance costs was adverse by £30 million in the year to 31 March 2006, compared to favourable movements of £93 million on items which were previously marked to market or otherwise fair valued in the year to 31 March 2005. This movement, together with net adverse exceptional costs of £20 million, partly offset the effect of the strong operational growth.

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

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TABLE 4

Profit before tax (£m)

2005/06 2004/05 Change

Reported profit before tax 625.1 552.4 72.7

Adjustments:

IAS 39/contracts now within the scope of IAS 39 30.1 (93.2) 123.3

Exceptional items 20.1 — 20.1

Adjusted profit before tax* 675.3 459.2 216.1

As shown in Table 5, the adjusted income tax charge for continuing operations was £162 million* for the year compared to £109 million* last year. The adjusted effective rate of tax was 23.9%* broadly in line with the prior year. Both years’ tax rates benefited from the settlement of prior years’ outstanding tax claims and from the release of provisions, following the agreement of outstanding items with the tax authorities and also from US Production Tax Credits (“PTCs”) associated with the windfarm investment programme in the US. The effective tax rate for 2006/07 is expected to increase, before taking account of any potential tax impact of IAS 39, partly because the group will not be able to recognise the full benefits from PTCs in future years’ tax charges. However, the impact will be offset by the benefit to the group of the adoption of new financing structures (as discussed within Section 4.3 ‘PPM Energy’) which, will be recognised in pre-tax profit. The cash tax payable in 2006/07 is also expected to be significantly higher than in the current year, partly because ScottishPower expects reduced benefit from cash repayments arising on the agreement of outstanding items. In addition, ScottishPower may decide to make payments on account in respect of open items currently held in current tax liabilities, in order to reduce potential interest expense. The reported income tax charge for continuing operations, as shown in Table 5, was £117 million for the year compared to £137 million for the prior year. The 2005/06 charge included tax credits of £9 million arising from net IAS 39 operating and financing derivative losses and £35 million from the exceptional items. The exceptional tax charge associated with the sale of Byley was offset by the utilisation of capital losses.

TABLE 5

Effective rate of tax (£m)/(%)

2005/06 2004/05 Change

Reported income tax charge 117.4 137.4 20.0

Adjustments – income tax:

IAS 39/contracts now within the scope of IAS 39 9.2 (28.1) (37.3)

Exceptional items 35.1 — (35.1)

Adjusted income tax charge* 161.7 109.3 (52.4)

Reported profit before tax 625.1 552.4 72.7

Reported effective rate of tax 18.8% 24.9% 6.1%

Adjusted profit before tax* 675.3 459.2 216.1

Adjusted effective rate of tax* 23.9% 23.8% (0.1)%

Adjusted profit for the year from continuing operations, as shown in Table 6, increased by 47% to £514 million* for the year. The continuing businesses’ operational growth more than offset the adverse impact of IAS 39 and net exceptional items, resulting in reported profit for the year from continuing operations increasing by 22% to £508 million.

TABLE 6

Profit from continuing operations (£m)

2005/06 2004/05 Change

Reported profit for the period from continuing operations 507.7 415.0 92.7

Adjustments:

IAS 39/contracts now within the scope of IAS 39 30.1 (93.2) 123.3

Exceptional items 20.1 — 20.1

Income tax effect on adjusting items (44.3) 28.1 (72.4)

Adjusted profit for the period from continuing operations* 513.6 349.9 163.7

The profit for the year from discontinued operations represents the post-tax earnings of PacifiCorp’s regulated activities, together with the impact of hedging PacifiCorp’s dollar earnings and disposal proceeds, the interest rate differential benefit arising from the group’s balance sheet hedging and the gain on sale. Profit for the year from discontinued operations was £1,036 million compared to a loss of £604 million for the prior year. The prior year results included an exceptional charge of £922 million for the impairment of goodwill allocated to PacifiCorp, while the 2005/06 results included the gain on sale of £619 million, resulting in a net exceptional loss in relation to PacifiCorp of £303 million. Further details of the results from discontinued operations are provided in Section 5, ‘Discontinued Operations – PacifiCorp’.

As shown in Table 7, the improved operational performance and the group’s success in delivering returns from its investment programme increased adjusted earnings per share for continuing operations by 46% to 27.85 pence* for the year. The favourable effect of the net exceptional items after tax was 0.81 pence per share but the adverse effect of IAS 39 diluted the underlying business growth and resulted in reported earnings per share for continuing operations of 27.54 pence, up by 22% from 22.60 pence.

Group adjusted earnings per share grew by 22% to 44.13 pence*, mainly due to the strong continuing operations’ performance offsetting the lower contribution from discontinued operations following a reduction in the interest rate differential benefit. Group reported earnings per share were 83.77 pence compared to a loss per share of 10.56 pence last year. The prior year loss was due to an exceptional charge of £922 million for the impairment of goodwill associated with PacifiCorp. The impairment amount excluded foreign exchange gains of £485 million, which, following completion of the sale of PacifiCorp, have been recognised within the Group Income Statement as part of the gain on sale of £619 million disclosed within discontinued operations. The principal reasons for the increase

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

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Business Review in reported earnings were the improved operational performance of our continuing businesses and the gain on sale of the disposal of PacifiCorp reported this year as opposed to the exceptional charge last year.

TABLE 7

Earnings per share (pence)

Continuing operations Group

2005/06 2004/05 2005/06 2004/05

Reported earnings/(loss) per share 27.54 22.60 83.77 (10.56)

Adjustments:

IAS 39/contracts now within the scope of IAS 39 1.12 (3.56) 1.21 (3.56)

Exceptional items (0.81) — (34.43) 50.36

PacifiCorp depreciation — — (6.42) —

Adjusted earnings per share* 27.85 19.04 44.13 36.24

The full year dividend was 25.0 pence per ordinary share (2004/05: 22.5 pence), a year-on-year increase of 11.1%. This dividend is the aggregation of the 5.2 pence per share paid in each of the first three quarters of 2005/06 on the ordinary shares in existence prior to the reorganisation of the company’s ordinary share capital on 12 May 2006, and the fourth quarter dividend of 9.4 pence per new ordinary share in existence following the reorganisation.

3.2 CASH FLOW AND NET DEBT

Cash generated from continuing operations increased by £183 million to £864 million for the year, with operating cash of £1,060 million partly offset by £196 million of working capital requirements, including increased gas and coal stocks and higher debtors reflecting customer growth and tariff increases. With an increased focus on working capital throughout the group, the businesses are undertaking initiatives such as managing inventories, improving the efficiency of billing operations and increasing direct debit penetration amongst retail customers. Although Energy Retail’s debtors increased compared to the prior year, its combined gas and electricity debtor days improved, demonstrating that the business’s tighter debt management strategy is already beginning to deliver benefits.

Net debt for continuing operations reduced by £1,944 million from 1 April 2005 to £83 million at 31 March 2006, reflecting the receipt of £2,768 million proceeds from the sale of PacifiCorp, net of the settlement costs of associated investment hedges. Net debt, excluding the sale proceeds, increased by £824 million to £2,851 million. Cash generated from continuing operations of £864 million was absorbed by: £150 million of net tax and interest payments; £1,045 million of capital investment mainly associated with the investment programme; £174 million equity investment, net of dividends, made into PacifiCorp prior to its disposal; and £428 million of dividend payments. Other favourable movements of £109 million included disposal proceeds from the sale of Byley. Net debt will increase significantly in June 2006 following the return of £2.25 billion of cash to shareholders and the £100 million contribution to the group’s pension schemes. The remaining net proceeds will be invested in the continuing businesses.

3.3 INVESTMENT

The group’s investment strategy is to drive the growth and development of its regulated and competitive businesses, through a balanced programme of capital investment. Investments in the regulated business aim to achieve at least the allowed rate of regulatory returns and the competitive businesses are expected to achieve returns in excess of their weighted average cost of capital. All investments are assessed on a risk-adjusted returns basis, are expected to be earnings enhancing and should support the aim to retain an A category credit rating for the group’s regulated operating subsidiaries.

For the year ended 31 March 2006, the group invested £1,003 million in its asset base. Of this, £951 million related to property, plant and equipment and intangible software additions, and £72 million related to acquisitions and fixed asset investments, offset by £20 million of customer grants and contributions. Of the net capital investment for the year, £673 million (67%) was invested for growth and £330 million was invested in refurbishment, upgrades and other projects. Growth investment included: windfarm development spend of £550 million in the UK and the US; new connections and network reinforcement spend of £74 million in the UK; and £49 million on other projects including gas storage expansion in the US.

Of the £673 million invested for growth expenditure, £74 million (11%) was invested in UK regulated activities and £599 million (89%) in the competitive businesses. Geographically, £493 million (73%) of growth spend was invested in the US and £180 million (27%) in the UK. The £330 million balance, representing network and generation plant refurbishment and overhauls and IT systems upgrade spend, primarily related to the UK.

3.4 GROUP BALANCE SHEET (“BAL ANCE SHEET”)

The adoption of IFRS required not only a number of reclassification and presentational changes to the Balance Sheet but also a change to the group’s opening net assets (at 1 April 2005) as a consequence of implementing IAS 32 (“Financial Instruments: Disclosure and Presentation”) and IAS 39.

IAS 39 has resulted in significant movements within net assets and, in particular, has resulted in the separate disclosure of derivative financial instrument (“DFI”) balances within non-current assets, current assets, current liabilities and non-current liabilities, and the establishment of a hedge reserve within equity. DFI balances are shown gross of deferred tax, whereas the hedge reserve balances are shown net. The majority of the movements in DFIs have either been reflected within, or offset by, similar movements flowing through the hedge reserve, and only a small proportion have impacted the group’s earnings for the year. Similarly, adopting IAS 39 has had no cash flow impact. Further discussion on IAS 39 is provided within Section 7.1 ‘Fair Value of Derivative Contracts’.

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

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TABLE 8

Implementation of IAS 32 and IAS 39 (£m)

Net assets Total equity

Balance at 31 March 2005 3,957.1 3,957.1

Hedge Retained MI

reserve earnings (non-equity) Other

IAS 32 reclassification of minority interests (“MI”) (52.5) (52.5)

IAS 39 derivative financial instruments (“DFI”)

Effectively hedged 606.9 606.9

Taken to retained earnings (61.7) (61.7)

545.2

IAS 39 deferred tax

Effectively hedged (190.3) (190.3)

Taken to retained earnings 80.7 80.7

(109.6)

IAS 39 reclassifications and derecognition of UK GAAP balances (154.2) (152.1) (2.1)

Net impact of adopting IAS 32 & IAS 39 228.9 416.6 (133.1) (52.5) (2.1)

Balance at 1 April 2005 4,186.0 4,186.0

The 31 March 2006 Balance Sheet shows the assets and liabilities of continuing operations only, as PacifiCorp’s assets and liabilities have been removed following completion of its sale. Last year’s Balance Sheet, however, includes PacifiCorp’s assets and liabilities. This, along with the IAS 32 and IAS 39 changes to opening net assets, makes it difficult to directly compare the two years’ Balance Sheets. Consequently, the £1,144 million increase in net assets to £5,101 million as at 31 March 2006 has been analysed into three elements: the impact of IAS 32 and IAS 39 on the 1 April 2005 Balance Sheet; the impact and subsequent disposal of PacifiCorp; and movements over the year, relating to continuing operations.

3.4.1 IMPLEMENTATION OF IAS 32 AND IAS 39

The group was required to adopt IAS 32 and IAS 39 with effect from 1 April 2005. As shown in Table 8, the cumulative opening adjustments which arose on the implementation of IAS 32 and IAS 39 increased net assets by £229 million.

IAS 32 sets out the presentation requirements for debt and own equity instruments and also the disclosure requirements for financial instruments. At 1 April 2005, the reclassification of minority interests from non-equity under UK GAAP to liabilities under IAS 32 reduced both net assets and total equity by £52 million.

IAS 39 sets out the accounting requirements for financial instruments. The definition of financial instruments in IAS 39 captures certain commodity contracts, loans and borrowings, trade receivables and payables, investments and cash as well as derivatives. At 1 April 2005 the adoption of IAS 39 impacted a number of balance sheet categories and increased net assets by £281 million. This was principally in relation to fair valuing the group’s energy commodity contracts, which fell within the scope of IAS 39. Fair value is estimated by calculating the

present value of the difference between the contract price and the applicable forward price curve. At 1 April 2005, the group’s contracts were in-the-money relative to forward prices, resulting in DFI balances (gross of tax) of £545 million being separately recognised within net assets. The difference between the £545 million and the £281 million net asset impact, reflects a related reversal of UK GAAP balances in respect of certain contracts which became subject to IAS 39 from 1 April 2005 and an associated net increase in deferred tax liabilities.

As the majority of the group’s DFIs were effective cash flow hedges, £417 million (net of tax) of the fair value recognised was taken directly to the hedge reserve. The balance of DFIs which did not qualify for hedge accounting and the reversal of the UK GAAP balances were reflected within the overall reduction in retained earnings of £133 million (net of tax) and a £2 million movement in the translation reserve.

3.4.2 PACIFICORP

There was an increase in PacifiCorp’s net assets of £488 million between 1 April 2005 and the date of disposal, reflecting its contribution to group profit prior to disposal and the net equity injections made by the group to fund operating and investing activities. The gain on disposal increased group net assets by a further £122 million (pre-tax).

3.4.3 CONTINUING OPERATIONS MOVEMENTS IN NET ASSETS

SINCE 1 APRIL 2005

The opening adjustments and PacifiCorp movements discussed above, increased net assets by £839 million. The remaining movement of £305 million arose in respect of the continuing businesses, principally from growth in retained earnings and increased DFI balances.

The investment programme during the year resulted in higher non-current assets, notably property, plant and equipment. Current assets were impacted by increases in coal and gas inventories in Energy Wholesale and PPM Energy, respectively; and by higher retail and wholesale gas and electricity debtors in Energy Retail & Wholesale.

The DFI balance at 1 April 2005 of £545 million included

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

ScottishPower Annual Report & Accounts 2005/06 13

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Business Review

fair value assets and liabilities in respect of continuing and discontinued operations. During the year, the value of DFIs increased by £349 million (gross of tax) as a consequence of rising commodity prices (relative to fixed contract prices), partly offset by the fair value increase in the embedded derivative within the group’s dollar convertible bonds, as a consequence of the company’s rising share price. The movement during the year was reflected by: £748 million gross gains on effective cash flow hedges taken directly to the hedge reserve, offset by £485 million gross gains removed from equity and recognised in the year; and £30 million of net fair value pre-tax losses taken directly to the Group Income Statement. The balance of £116 million represented PacifiCorp movements, favourable mark-to-market movements on net debt and the impact of foreign exchange.

Retirement benefit obligations, disclosed as part of non-current liabilities, were £156 million at 31 March 2006. This represented a reduction of £55 million in the year, principally due to the revaluation of the group’s continuing pension obligations which resulted in a net gain of £49 million (gross of tax). During March 2006, a £28 million lump sum contribution was made into the pension schemes and upon completion of the return of cash in June 2006, a further contribution of £100 million will be made and thereafter four further annual payments of £13.2 million will be made, commencing on 31 March 2007, subject to a deficit continuing in the schemes at each due payment date.

The overall increase in net assets was reflected in a corresponding increase in shareholders’ equity. The movements in equity are represented by net income and expenses recognised directly in equity, the profit for the year and other equity movements, most notably the dividend payments. An analysis of the movements in equity is provided in Note 33 to the Accounts.

3.5 SIGNIFICANT CHANGES

Any significant developments and post-balance sheet events that have occurred since 31 March 2006 have been noted in this Annual Report & Accounts and the report on Form 20-F, expected to be filed with the United States Securities and Exchange Commission (“SEC”) in June 2006. Otherwise, there have been no significant changes since 31 March 2006.

3.6 FUTURE TRENDS

Shareholder value is expected to be created through continuous improvement in operational performance, increasing the focus on cash generation and an investment programme aiming to deliver attractive risk adjusted returns while retaining an A category credit rating for the group’s regulated operating subsidiaries.

The level of net capital investment is expected to be approximately £1.2 billion next year, based on a US dollar/UK sterling exchange rate of approximately $1.80. This will include further investment in the renewal and expansion of the group’s network, plant overhauls and the installation of Flue Gas Desulphurisation (“FGD”) equipment at Longannet power station, new wind projects announced in the US and UK and, subject to Board approval, the commencement of the 322 megawatt (“MW”) Whitelee windfarm in the UK.

Continuing Operations

4.1 ENERGY NETWORKS

4.1.1 ACTIVITIES

Three wholly-owned subsidiaries of SPUK – SP Transmission Limited, SP Distribution Limited and SP Manweb plc – are the “asset-owner companies” holding the group’s UK regulated assets and transmission and distribution licences. A further wholly-owned subsidiary of SPUK – SP Power Systems Limited (“PowerSystems”) – provides asset management expertise and conducts the day-to-day operation of the networks.

PRINCIPAL BUSINESS ACTIVITIES

The asset-owner companies act as an integrated business unit to concentrate expertise on regulatory issues and investment strategy. PowerSystems implements work programmes commissioned by and agreed with the asset-owner business. Strict commercial disciplines are applied at the asset owner-service provider interface, with PowerSystems operating as a contractor to the transmission and distribution business unit. An integrated senior management team within Energy Networks applies the benefits of growing expertise in asset ownership; financing and operational service provision to the management of the group’s regulated networks.

TRANSMISSION AND DISTRIBUTION

ScottishPower owns a substantial UK electricity transmission and distribution network which extends to approaching 112,000 km, with some 65,000 km of underground cables and 47,000 km of overhead lines, comprising both the distribution system to customers in its two authorised areas and, in Scotland, its high-voltage transmission system (132 kilovolt (“kV”) and above, including those parts of the England-Scotland interconnector which are in its Scottish authorised area). A single, Great Britain-wide system operator, National Grid, has operational control of the Great Britain transmission system, including the balancing of generation and demand in Scotland. However, ScottishPower retains network ownership and all associated responsibilities, including development of the network.

Table 9 shows key information with respect to Energy Network’s transmission and distribution services in 2005/06.

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

14 ScottishPower Annual Report & Accounts 2005/06

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TABLE 9

Energy Networks distribution and transmission systems key information 2005/06

ScottishPower Manweb Total

Franchise area 22,950 km2 12,200 km2 35,150 km2

System maximum demand 4,088 MW 3,092 MW 7,180 MW

Transmission network (km)

Underground 220 — 220

Overhead 3,750 — 3,750

Distribution network (km)

Underground 38,500 26,200 64,700

Overhead 21,300 21,900 43,200

These were operated under licences issued by the Gas and Electricity Markets Authority (“the Authority”) and held by the transmission and distribution businesses, which were entitled to charge for the use of the systems on terms approved by the Authority under various price control formulae. The income derived is dependent on the demand for electricity by customers in the authorised areas. 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. Tables 10 and 11 set out the demand in gigawatt hours (“GWh”) by customer type within the broadly stable levels of electricity transported over the distribution systems in the ScottishPower and Manweb home areas during the five most recent financial years.

TABLE 10

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

Year Residential % Business % Total

2001/02 8,698 39 13,864 61 22,562

2002/03 8,643 39 13,689 61 22,332

2003/04 8,620 39 13,639 61 22,259

2004/05 8,739 39 13,903 61 22,642

2005/06 8,927 41 12,970 59 21,897

TABLE 11

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

Year Residential % Business % Total

2001/02 5,387 32 11,540 68 16,927

2002/03 5,512 33 11,233 67 16,745

2003/04 5,862 35 11,018 65 16,880

2004/05 6,310 37 10,880 63 17,190

2005/06 6,247 36 11,181 64 17,428

ASSET MANAGEMENT

Within the PowerSystems business unit, the focus continues to be on cost-effectiveness and service quality improvement. Its principal business activities involve the construction and refurbishment of the ScottishPower transmission and distribution systems, their maintenance and related fault repair. PowerSystems acts as the major service provider to the ScottishPower distribution businesses and as the primary customer contact agent for network-related matters. PowerSystems continues to focus strongly on the efficient delivery of these services under contract.

In October 2005, the group acquired Alfred McAlpine Utility Services Limited’s 50% interest in the parties’ 50/50 joint venture, Core Utility Solutions Limited (“Core Utilities”), to take further advantage of the opportunities presented by the requirement for competitive provision of connections to distribution networks.

4.1.2 STRATEGY

Energy Networks plans to deliver returns at, or in excess of, allowed returns on an expanding regulated asset base. The management focus of the transmission and distribution business is to outperform allowed regulatory returns from the provision of efficient, coordinated and economical networks that are open to licensed users on a non-discriminatory basis (in order to facilitate competition in generation and supply) and operated to approved standards of safety and reliability. Investment is planned to grow the regulated asset base, to improve security of supply and network performance and facilitate the connection of renewables. Ofgem sets targets for network performance and efficiencies and the regulatory framework provides financial incentives to improve network performance (in terms of Customer Minutes Lost (“CML”) and Customer Interruptions (“CI”)) and customer satisfaction. In 2005/06, network performance improved by 11% year-on-year and PowerSystems is focused on maximising the financial benefit to be obtained from the available incentives over the course of the recently renewed price control period.

4.1.3 FINANCIAL REVIEW OF THE YEAR TO 31 MARCH 2006

Energy Networks’ key financial information is shown in Table 12.

TABLE 12

Energy Networks (£m)

2005/06 2004/05 Change

External revenue 562.2 380.1 182.1

Reported operating profit 506.6 427.4 79.2

Adjustments: exceptional item 18.0 – 18.0

Adjusted operating profit* 524.6 427.4 97.2

In the year, Energy Networks’ external revenue increased by £182 million to £562 million. External revenue accounts for some 65% of Energy Networks’ total revenue, as a significant portion of its sales are internal to the Energy Retail & Wholesale business.

External electricity revenues increased by £169 million in the year mainly due to a change in the billing arrangements under BETTA and higher regulatory income from price increases as a result of the recent price control reviews. The change in billing arrangements increased external revenues as transmission exit costs previously charged internally to Energy Retail & Wholesale are now billed externally to National Grid, who then incorporate these in charges when billing Energy Retail & Wholesale. Further increases in external regulatory income were largely due to price rises, as the volume of

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

ScottishPower Annual Report & Accounts 2005/06 15

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electricity units distributed in the year in the combined ScottishPower and Manweb service areas remained broadly in line with last year at 39,325 GWh. Other non-regulatory external revenues increased by £13 million to £87 million due to growth in Core Utilities’ market sales and other externally rechargeable work, with both these increases being volume related.

Energy Networks’ reported operating profit increased by £79 million to £507 million in the year, including exceptional costs of £18 million relating to the corporate restructuring programme.

Adjusted operating profit increased by £97 million or 23% to £525 million*. Net regulated transmission and distribution use of system revenues increased by £116 million. This was mainly due to higher allowed revenues as a result of the Distribution Price Control Review and the Transmission Price Control Extension, which took effect from 1 April 2005 and provided for higher allowances for tax and pension costs, the level of allowed capital expenditure and the allowed cost of capital. Net costs increased by £19 million during the year, largely due to higher rates and depreciation of £5 million and movements in one-off items of £13 million, principally relating to a rebate and a gain on the sale of gas assets in the prior year, not repeated. The business continued to focus on cost control with efficiency improvements allowing increased operating activity to be managed within the existing cost base.

The Distribution Price Control Review resulted in a 55% increase in the allowed capital expenditure programme over the five-year period of the review and, on which, Energy Networks can earn allowed returns. The investment programme focuses on network reinforcement and expansion and driving improved network performance. In 2005/06, Energy Networks invested £282 million with £74 million (26%) for growth, principally deployed on new connections, the Renewable Energy Transmission Study programme, system reinforcement and the completion of projects associated with

TABLE 13

Energy Retail & Wholesale customer statistics

2005/06 2004/05 Change % change

Energy sales

Retail electricity GWh 26,667 28,034 (1,367) (5)%

Wholesale electricity GWh 33,213 32,998 215 1%

Retail gas Therms (millions of) 1,491 1,321 170 13%

Customer numbers

Electricity and gas accounts ‘000s 5,251 5,115 136 3%

Domestic electricity customers

Home area retention % 60 61 (1) (1)%

Average annual usage kWh 4,953 5,0641 (111) (2)%

Average annual revenue per customer £ 385 3541 31 9%

Revenue per kWh pence 7.8 7.0 0.8 11%

Domestic gas customers

Average annual usage Therms 691 7001 (9) (1)%

Average annual revenue per customer £ 387 3331 54 16%

Revenue per Therm pence 55.9 47.5 8.4 18%

1 The methodology applied in the average annual usage and revenue customer statistics changed during the year. The 2004/05 figures have been restated and are presented on a consistent basis with the 2005/06 figures.

the Liverpool city centre regeneration programme which result in improved security of supply. The regulated asset base now amounts to £2.94 billion.

4.1.4 FUTURE TRENDS

Energy Networks is undertaking a number of initiatives to further improve the reliability and performance of the network. The four-year programme to install some 5,000 network controllable points that will enable the business to minimise the impact of outages on its customers will continue through 2006/07. In addition, as part of Ofgem’s Innovation Funding Initiative, the business has established industrial, manufacturing and academic partnerships aimed at improving the performance of the network and is currently developing new network designs to accommodate distributed generation.

Discussions continue with Ofgem on the next

Transmission Price Control Review, which will apply for the five-year period from April 2007. The key challenge for Energy Networks is to ensure a fair outcome with sufficient and timely funding for the considerable increase in capital investment necessary to maintain the safety, integrity and performance of the network and develop network infrastructure to support development of renewable generation.

4.2 ENERGY RETAIL & WHOLESALE

4.2.1 ACTIVITIES

Energy Retail & Wholesale operates in gas and electricity markets which became fully competitive with the ending of residual price controls on 31 March 2002; although Ofgem continues to enforce licence conditions and regulate quality of service. Energy Retail & Wholesale together principally comprise five wholly-owned subsidiaries: ScottishPower Generation Limited owns and operates the group’s generation assets in the British Isles and holds the group’s generation licence; ScottishPower Energy Management

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

16 ScottishPower Annual Report & Accounts 2005/06

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Limited is responsible for commercial running of the power stations including scheduling and fuel purchasing, for managing retail economics and pricing, and for managing commodity risk through buying and selling wholesale energy via ScottishPower Energy Management (Agency) Limited; ScottishPower Energy Retail Limited is the gas and electricity supply company and holder of the group’s supply licences; and SP Dataserve Limited is the data management and metering company.

Table 13 shows the business’ key customer statistics.

PRINCIPAL BUSINESS ACTIVITIES

Energy Wholesale operates ScottishPower’s generation assets in the British Isles and manages the company’s exposure to the UK wholesale electricity and gas markets; Energy Retail is responsible for energy supply, the sales and marketing of electricity and gas to customers throughout Great Britain, together with the associated customer registration, billing and receipting processes and handling enquiries in respect of these services.

POWER PLANT PORTFOLIO, FUEL STRATEGY

AND GENERATION SALES

Energy Wholesale operates over 6,300 MW of generating capacity, see Table 22 (page 28) comprising coal, gas, hydroelectric and wind power generation assets, giving the business a particularly flexible portfolio. In February 2006, Energy Wholesale announced that it had opted to be regulated under the Large Combustion Plant Directive (“LCPD”) in respect of its coal-fired power station at Longannet, Fife. This will result in a major investment in FGD equipment thus freeing the facility from certain operating restrictions that would otherwise apply, maintaining the balance of the group’s generation portfolio and potentially extending Longannet’s life beyond 2020, in addition to the environmental benefits that this investment will bring.

During the year to March 2006, wholesale energy prices were higher than historical standards and the outlook remains uncertain. ScottishPower’s fuel purchasing strategy aims to achieve competitive fuel prices while balancing the need for security and flexibility of supply. The major components of the fuel portfolio are coal and gas. The business has eight long-term contracts with terms of greater than five years for the supply of gas.

Generation plant is despatched economically and output is managed to maximise value, including optimising the position in the balancing market. In 2005/06, some 24 terawatt hours (“TWh”) were despatched, both to contribute towards the approximate 27 TWh of retail and wholesale demand provided by the Energy Retail & Wholesale trading counterparty and customer base and to maintain export volumes to England & Wales and to Northern Ireland. The additional demand was met through Energy Wholesale’s short- and long-term contracts.

ENERGY MANAGEMENT AND COMMERCIAL ARRANGEMENTS

In addition to scheduling its own generation capacity and managing the long-term bulk gas contracts, Energy Wholesale, through its energy management operation, uses medium- and short-term contractual arrangements to complete its energy balancing of the whole portfolio of assets and customers. A Great Britain-wide wholesale electricity market was introduced on 1 April 2005 through BETTA, providing a wider opportunity for the sale of the group’s generation output and the deployment of its proven skills in providing market balancing services. Wholesale contracts have varying terms and short-term and spot prices vary markedly by time of day, week and year, whereas end-user electricity and gas prices are generally set over longer time frames. Through its activities in the electricity, gas and coal markets, ScottishPower’s Energy Wholesale business seeks to secure competitive advantage for Energy Retail & Wholesale through hedging and optimising its position across the energy value chain, from fuel procurement and plant

despatch through to retail pricing, continuously evaluating and managing risk exposure. This process is described further in the ‘Energy Price and Volume Risk Management’ section on page 39.

ScottishPower’s Hatfield Moors gas storage site enhances the flexibility of the energy management position of the business, both in meeting peak demands of supply customers and responding to the volatility of gas prices between midweek and weekends. In addition, its bulk gas contracts allow the gas to be sold out or used in the group’s power stations, giving further flexibility. In July 2005, the group announced the sale of its underground gas storage project at Byley for £96 million while at the same time securing a 15-year gas storage contract. Once built, Byley will provide Energy Wholesale with greater access to reliable gas storage with high deliverability, providing further flexibility benefits.

ENERGY SUPPLY

Since September 1998 when, under the provisions of the Electricity Act 1989 (“Electricity Act”), competition was extended to residential electricity customers, a strategic focus of the ScottishPower energy supply business has been on its core areas, residential and small business customers in the ScottishPower and Manweb home areas, whilst also seeking profitable additional business outside these historical regional boundaries. Retention of home area domestic customers stands at 60% whilst innovative product offerings, targeted sales efforts and wide-ranging sales channels (including a number of affinity deals across a range of market sectors and the use of e-commerce channels) have helped develop a Great Britain-wide customer base which now stands at 5.25 million energy accounts. The business transformation programme introduced in 2001 continues to drive improvements across Energy Retail and has helped to deliver increased direct debit penetration and reduced customer churn rates, in addition to cost benefits in areas such as billing, debt and customer registration.

METERING AND DATA MANAGEMENT

In the competitive energy market Energy Retail, through SP Dataserve Limited, operates end-to-end process and data management in order to maximise efficiencies in the provision

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

ScottishPower Annual Report & Accounts 2005/06 17

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Business Review and control of registration and metering data for ScottishPower and other agency arrangements. Data management covers the establishment of new customers, maintenance of existing customers and accuracy of energy settlement. To effectively manage gas and electricity customers, ScottishPower Energy Retail Limited has continued to contribute to improvements in billing performance through the management of its metering agents, who are responsible for the provision of much of the data.

4.2.2 STRATEGY

The Energy Retail & Wholesale management teams oversee activities across the energy value chain, maximising value from a diverse generation portfolio through to a national customer base of 5.25 million, via an integrated commercial and energy management activity that acts to balance and hedge energy needs. As an active market participant, Energy Retail & Wholesale engages fully in regulatory and contractual debate and in the consultation processes involved in the UK

Government’s review of energy policy. In the meantime, the integrated businesses aim to leverage the benefits of Energy Wholesale’s flexible generation asset base and commercial operations to deliver sustained earnings through improved business processes and customer service; and to develop Energy Wholesale’s position in renewable generation and other aspects of the emerging market for environmental instruments.

4.2.3 FINANCIAL REVIEW OF THE YEAR TO 31 MARCH 2006

Energy Retail & Wholesale’s key financial information is shown in Table 14.

TABLE 14

Energy Retail & Wholesale (£m)

2005/06 2004/05 Change

External revenue 4,327.3 3,685.0 642.3

Reported operating profit 375.0 185.3 189.7

Adjustments:

IAS 39/contracts now within the scope of IAS 39 (88.7) (91.8) 3.1

Exceptional items (72.2) — (72.2)

Adjusted operating profit* 214.1 93.5 120.6

Energy Retail & Wholesale’s revenue increased by £642 million to £4,327 million, reflecting tariff rises within the retail electricity and gas markets, which were required due to increasing commodity prices; and also, to a smaller extent, growth in customer numbers.

Retail electricity sales improved by £179 million to £1,801 million primarily due to tariff increases and increased domestic volumes from out-of-area customer gains. This was partly offset by lower large business volumes, which contributed to the 5% reduction in electricity volumes to 26,667 GWh for the year.

Retail gas sales also improved, up £200 million to £823 million, due to a combination of tariff increases and customer number growth. Retail gas volumes increased by 13% to 1.5 billion therms.

On 1 April 2005, the introduction under BETTA of a Great Britain-wide wholesale electricity market replaced the England

& Wales wholesale electricity market and the separate Scottish arrangements (such as agency sales made directly to third-party suppliers). For the year, UK external wholesale electricity sales increased by £56 million to £1,232 million largely due to the continuing rise in market prices. However, the price rise impact was offset to a notable extent by a reduction in external sales volumes, as Damhead Creek revenues shifted increasingly from being external to internal, following its integration into the group’s generation plant portfolio. In overall volume terms, owned generation output meets around 80% of customer sales including large commercial and industrial sites. The remaining volume is purchased on the wholesale market but in order to achieve balance on a half-hour by half-hour basis and reflecting the volatility of prices, during the year approximately 39 TWh of purchases were made compared to 33 TWh of sales. Last year’s wholesale market purchases were 42 TWh compared to 33 TWh of sales. Purchase volumes reduced by 7% year-on-year and sales volumes increased by less than 1%.

Other revenues increased by £207 million to £471 million and mainly related to wholesale gas sales, which increased as a result of the continuing rise in market prices and volume growth.

Energy Retail & Wholesale’s reported operating profit increased by £190 million to £375 million. This was primarily due to the improved operational performance of £121 million and the effect of net favourable exceptional items of £72 million in respect of the gain on sale of the Byley gas storage facility, net of corporate restructuring costs, partly offset by a £3 million reduction in IAS 39 related movements.

Adjusted operating profit increased by £121 million or 129% to £214 million* as the business benefited from its recent investments in generation capacity and strong energy management activities.

Energy Wholesale’s renewable activities delivered £8 million of this increase reflecting new contributions from windfarms and higher Renewable Obligations Certificates (“ROCs”) revenues. The full year impact of Damhead Creek and Brighton power plants, including benefits from associated gas contracts, contributed an additional £108 million. A further £8 million came from growth in customer numbers, largely due to gas and out-of-area electricity gains. In response to the sustained period of high wholesale power prices experienced during the year, it was necessary to raise tariffs. The increase in tariffs contributed to revenue growth but this was more than offset by higher commodity, distribution and transmission costs and increased Energy Efficiency Commitment (“EEC”) costs resulting in a net adverse movement of £32 million. Energy Wholesale’s flexible and competitive plant operating regime performed very well in the new BETTA environment and delivered an additional £27 million of operating profit. Realised gains relating to the hedging programme delivered £13 million. Net operating costs increased by £11 million, largely due to retail metering costs, with other operational cost movements being offset by 6 Sigma and corporate restructuring efficiency savings.

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

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Energy Retail & Wholesale’s net capital investment was £224 million for the year, with 47% invested in windfarm developments. During the year, wind generating capacity increased by more than 80% with the completion of Black Law phase one (97 MW), Coldham (16 MW) and Callagheen (17 MW) windfarms. As a result ScottishPower is the leading onshore windfarm developer in the UK with 288 MW operational and a further 490 MW currently under construction or in receipt of planning approvals. In addition to windfarm developments, the business also undertook a wide programme of refurbishment and overhaul spend during the year, including initiatives to further improve plant performance and availability at the coal-fired stations, and to increase the flexibility of the Combined Cycle Gas Turbine (“CCGT”) plant.

The underground natural gas storage project at Byley was sold during the year. As part of the deal, Energy Wholesale negotiated a 15-year gas storage contract, which provides the business with a secure access to reliable gas storage with high deliverability. The sale, combined with securing the gas storage contract, presented an attractive opportunity to immediately maximise value from the development for shareholders and resulted in a gain on sale of £81 million.

In February 2006, Longannet power station (2,304 MW) was opted into the LCPD. Installation of FGD equipment will commence in summer 2006 using seawater-based technology at an estimated cost of £170 million. Installing FGD equipment will help maintain a balanced portfolio, will contribute significantly to the security of energy supply in the UK and has the potential to extend Longannet’s life beyond 2020.

4.2.4 FUTURE TRENDS

In 2005/06, wholesale energy prices were high by historic standards, with gas and power prices increasing by over 60% compared to the prior year, and the outlook remains uncertain. Energy Wholesale’s forward commodity procurement strategy has ensured that the business is over 90% hedged for 2006/07 and substantially hedged for 2007/08 across all commodities, including carbon dioxide (“CO2”) emissions. The emphasis on a market-based framework for energy policy set out the UK Government’s White Paper of February 2003 (and in its subsequent annual implementation reports), seems likely to imply that power prices will tend to move towards the long-run marginal cost of gas-fired generation, augmented by the developing impact of carbon trading. International investments, regulatory and contractual changes are expected to influence wholesale gas prices over the coming decade but are dependent upon agreements amongst a substantial number of parties, so are likely to develop gradually. The current UK Government energy review has re-opened discussion of the optimal generation fuel mix required to provide acceptable security of supply and is due to report in the summer of 2006.

The 2003 restatement of the public policy emphasis on renewable generation, and the extension to 2015 of the Renewables Obligation (“RO”) targets, mean that significant expansion of renewable generation remains a key part of the Energy Retail & Wholesale strategy. Final planning approval to construct Europe’s largest on-shore windfarm, the 322 MW Whitelee project located south of Glasgow, was received in April 2006. Subject to Board approval, construction of Whitelee should start in summer 2006. Including Whitelee, the business now operates or has planning approvals for 778 MW of wind generation, representing almost 80% of its 2010 target of 1,000 MW. ScottishPower has also received widespread recognition for its renewables programme, including the Queen’s Award for Enterprise for its collaborative and responsible approach to windfarm development and a Scottish Green Energy award for the Black Law windfarm.

Energy Retail’s focus is on gaining profitable customers and the current period of high wholesale prices led the business to slow its rate of customer growth. This is a policy ScottishPower would

expect to continue in the short-term, whilst concentrating on maximising the value of the Energy Retail customer base.

4.3 PPM ENERGY

4.3.1 ACTIVITIES

Based in Portland, Oregon, PPM Energy, the group’s US energy business, is a growing competitive energy provider. It owns or controls significant assets in 12 US states and in Canada. PPM Energy commenced substantive operations in 2001 and is growing through investment and application of expertise in operations and energy management activities in the areas of renewable power, natural gas storage and hub services and gas-fired generation. A summary of PPM Energy resources is given in Table 15.

PRINCIPAL BUSINESS ACTIVITIES

PPM Energy’s principal assets are renewable and thermal generation resources and natural gas storage facilities. PPM Energy aims to leverage the benefits of its flexible asset base and contracts to extract value across the gas and electricity sectors whilst integration of plant operations, contract despatch and energy management provide additional value.

TABLE 15

PPM Energy resources

Total owned or controlled at March 2006 Approved new projects

Wind generation

Installed capacity at March 2006 MW 1,405

Confirmed new projects approved by 24 May 2006 MW 857

Thermal generation

Plant net capability at March 2006 MW 806

Total all generating facilities MW 2,211 857

Gas storage

Capacity under ownership BCF 50.5 9.5

Capacity under contract BCF 34.0 —

Total gas storage capacity BCF 84.5 9.5

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

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POWER PRODUCTION AND WHOLESALE SALES

PPM Energy owns or controls more than 2,200 MW of generating capacity, including power purchase and operating agreements, see Table 23 (page 29). PPM Energy balances its supply and sales, selling a substantial amount of its supply forward under long-term contracts. In its electricity business, PPM Energy serves a wide variety of wholesale energy customers including municipal agencies, public utility districts and investor-owned utilities. These customers are primarily located in wholesale energy markets served by the 1.8 million square mile Western Electricity Coordinating Council service territories in the western US and the Mid-Continent Area Power Pool service territories in the upper midwest US, although PPM Energy’s operations are now extended into the northeastern US.

WIND POWER

PPM Energy has more than 1,700 MW of wind power in construction or operation currently under its control. PPM Energy balances its supply portfolio with sales to wholesale customers, placing almost all of its wind power output in long-term contracts. Major customers include the cities of Seattle, Sacramento, Pasadena and Anaheim, as well as investor-owned utilities such as Pacific Gas & Electric Group, Xcel Energy and the federal Bonneville Power Administration.

GAS STORAGE AND HUB SERVICES

PPM Energy’s subsidiary ENSTOR, Inc. (“ENSTOR”) currently owns the Katy gas storage facility in Texas and the Grama Ridge facility in New Mexico. ENSTOR also manages the group’s gas storage facility located in Alberta, Canada. Each is connected into substantial interstate and intrastate pipeline networks serving well-diversified customer bases under firm, short- and long-term contract arrangements. In addition to 50.5 billion cubic feet (“BCF”) of gas storage capacity under the group’s ownership, PPM Energy has 34 BCF of contracted capacity in third-party storage facilities in Canada and the US. PPM Energy also has begun development of a 9.5 BCF bedded salt cavern gas storage in west Texas and has expanded the Grama Ridge facility by 1.5 BCF.

4.3.2 STRATEGY

PPM Energy will continue to build on its leading positions in wind generation and independent gas storage, while expanding its energy management and origination activities. PPM Energy’s confidence in its ability to deliver projects with attractive returns, and to undertake further wind power financing structures as windfarms currently under construction become operational, has allowed the business to increase its 2010 renewables target by over 50% to at least 3,500 MW developed or controlled by PPM Energy. PPM Energy is also planning to build and operate a 15 BCF gas storage facility in Texas known as the “Houston Hub”. Subject to obtaining the necessary permits and Board approval, this facility is expected to be operational by spring 2010. This facility will provide PPM Energy with a unique opportunity to expand its gas storage business in the Gulf Coast. PPM Energy seeks to create value by securing quality assets at strategic locations and by entering into long-term contracts with creditworthy customers. Plant operations are optimised during periods of low energy prices, by displacing energy generation with low-priced electricity purchases, and selling the displaced gas or injecting the displaced gas in storage. Operations are also optimised by using transmission and contract delivery flexibility to manage locational price differences in both gas and electricity.

In May 2006, PPM Energy completed its first wind portfolio financing structure for 141 MW. Through this financing structure the group will realise the value of the tax benefits associated

with these PPM Energy wind projects. PPM Energy receives both an initial upfront cash payment and future cash flows based on the value of the windfarms. PPM Energy retains significant ownership rights and continues to operate the facilities. During 2006/07 PPM Energy expects to undertake similar transactions for substantial portions of its owned windfarm assets which will provide significant capital for reinvestment.

4.3.3 FINANCIAL REVIEW OF THE YEAR TO 31 MARCH 2006

PPM Energy’s key financial information is shown in Table 16.

TABLE 16

PPM Energy (£m)

2005/06 2004/05 Change

External revenue 545.9 502.0 43.9

Reported operating profit 53.0 60.0 (7.0)

Adjustments:

IAS 39 / contracts now within the scope of IAS 39 3.0 (1.4) 4.4

Exceptional items 34.6 — 34.6

Adjusted operating profit* 90.6 58.6 32.0

PPM Energy’s revenue for the year improved by £44 million to £546 million, after a £14 million favourable impact of the stronger dollar. Dollar revenue increased by $48 million to $965 million largely due to growth in owned and contracted gas storage activities as the use of storage capacity was successfully optimised to take advantage of the rising gas prices and volatile market conditions that stemmed from the tight supplies of gas and storage in North America. Energy management activities also benefited from higher electricity power prices.

PPM Energy’s reported operating profit reduced by £7 million to £53 million as an improved operational performance of £32 million was more than offset by unfavourable IAS 39 related movements of £4 million and exceptional items of £35 million, relating to the corporate restructuring programme and probable liabilities associated with a credit support facility which are discussed above in Section 3.1. Adjusted operating profit increased by £32 million or 55% to £91 million*. Adjusted dollar operating profit was $56 million higher for

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

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the year at $154 million*. In addition, the group’s tax charge was reduced by $23 million (2004/05: $12 million) as a result of PTCs associated with the windfarm portfolio.

The business successfully optimised the use of its gas storage capacity to take advantage of volatile market conditions and this has contributed significantly to the higher returns from gas storage activities, with owned gas delivering an additional $27 million and contracted gas adding an additional $20 million to operating profit. The contribution from energy management activities, which focus on the management of core assets and the optimisation of wholesale energy and transmission positions, increased by $18 million. The contribution from wind generation was ahead of last year by $8 million as a strong performance from PPM Energy’s owned plants, including those brought online this year, more than offset underperformance of third-party plants. Operating costs, including depreciation, increased by $17 million as the business continued to grow.

PPM Energy’s net capital investment was £497 million for the year. Of this £493 million was for growth, including £445 million invested in wind generation. The business successfully completed the construction of five new windfarms, adding 574 MW of renewable generation to its owned wind capacity and consisted of: the 75 MW Klondike II plant in Oregon; the 100 MW Trimont windfarm in Minnesota; the 150 MW Shiloh windfarm in California; the 150 MW Elk River windfarm in Kansas; and 50% of the 198 MW Maple Ridge windfarm in upstate New York. PPM Energy’s owned wind capacity has more than tripled in the year and there is now 1,405 MW under the business’s control, with approximately 90% of the output sold under long-term contracts.

Gas-related expenditure of £43 million included expansion investment in the Waha gas storage development in west Texas totalling 9.5 BCF, due to commence operations in 2007, and the 1.5 BCF expansion to PPM Energy’s existing gas storage facility at Grama Ridge in New Mexico, which is now operational.

4.3.4 FUTURE TRENDS

The rate of PPM Energy’s expansion is determined by the availability of attractive market opportunities for growing its portfolio of assets, and also by public policy. For example, the US Energy Bill, signed in August 2005, extended PTCs for two years to the end of 2007. PPM Energy expects to see profitability growth from returns on wind assets currently under construction and has approved plans to build at least 857 MW of new wind generation in the 2006 and 2007 calendar years. Construction has commenced at the 200 MW Big Horn project in Washington and at the 100 MW Leaning Juniper project in Oregon. The business is expanding the Maple Ridge windfarm by a further 62 MW. These projects are all expected to become operational during 2006. Towards the end of 2007, PPM Energy expects to commission projects totalling some 500 MW. PPM Energy’s energy management and origination business continues to build a portfolio of transport rights and marketing alliances to complement its gas storage activities. In April 2006, PPM

Energy announced a 10-year gas purchase and supply agreement with Cheniere LNG Marketing, Inc. (“Cheniere”). The agreement provides a framework for up to 600,000 MMBTUs of natural gas per day from Cheniere at a negotiated price discounted to a major market index, and positions PPM Energy to participate in an important new supply source for US gas markets.

4.4 UNALLOCATED ACTIVITIES

Unallocated income and expense comprises corporate costs and the results of non-regulated US activities retained by the group, which were previously reported within the PacifiCorp business.

The unallocated activities reported operating expenses of £65 million compared to operating income last year of £1 million. The adverse movement of £65 million was largely due to reduced Synfuel royalties of £23 million and exceptional costs of £40 million. The exceptional costs related to an impairment of finance lease receivables and corporate restructuring. These are discussed in more detail in Section 3.1 ‘Group Income Statement’, above. Other non-regulated US net costs also increased but these were largely offset by lower corporate costs reflecting savings delivered to date from the restructuring programme.

Discontinued Operations –PacifiCorp

BACKGROUND

In November 1999, ScottishPower acquired PacifiCorp. In May 2005, the ScottishPower Board concluded that, in the light of the scale and timing of the capital investment required in PacifiCorp and the likely profile of returns from that investment, shareholders’ interests were best served by a sale of PacifiCorp and return of cash to shareholders. The sale to MidAmerican was completed on 21 March 2006.

FINANCIAL REVIEW OF THE YEAR TO 31 MARCH 2006

The profit from discontinued operations represents the post-tax earnings of PacifiCorp’s regulated activities to 20 March 2006, together with the impact of hedging PacifiCorp’s dollar earnings and disposal proceeds and the interest rate differential benefit arising from the group’s balance sheet hedging. The results also include a £619 million gain on sale of which £485 million relates to foreign exchange gains recycled from reserves. PacifiCorp’s key financial information is shown in Table 17.

PacifiCorp’s reported operating profit increased by £1,197 million to £810 million in the year, largely due to last year’s results including an exceptional impairment charge of £922 million. The results to 20 March 2006 benefited from lower depreciation and amortisation costs which were favourable by £184 million, as under IFRS, PacifiCorp’s non-current assets were not subject to depreciation or amortisation charges from 24 May 2005; and also from favourable IAS 39 movements of £65 million. Adjusted operating profit increased by £20 million to £554 million* largely due to favourable foreign exchange

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

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movements as operational performance was broadly in line with last year, despite the exclusion of 11 days’ trading due to the timing of completion of the sale.

Reported net finance costs were £112 million higher at £178 million primarily due to the interest differential benefit reducing by £49 million as a result of a reduced differential between UK and US interest rates and IAS 39 fair value losses on financing derivatives of £60 million. After adjusting for the effect of IAS 39, adjusted net finance costs were £52 million higher at £119 million*.

Reported profit for the year improved by £1,640 million to £1,036 million largely due to last year’s results including an exceptional impairment charge of £922 million and this year’s results including the gain on sale of £619 million, resulting in a net exceptional loss in relation to PacifiCorp of £303 million.

PacifiCorp’s reported results also benefited from lower depreciation and amortisation costs. The favourable impact of IAS 39 on operating profit was largely offset by the adverse impact of IAS 39 on net finance costs.

As previously advised, the gain on sale of PacifiCorp included £485 million of foreign exchange gains, which were recycled from reserves on completion of the sale. Also included in the gain were the benefits from early completion of the sale relative to the timing and discounting assumptions made at the time of the impairment, partly offset by a £19 million impairment charge in respect of West Valley, a thermal generating plant leased by PPM Energy to PacifiCorp. The terms of the plant lease were amended as part of the final settlement achieved with MidAmerican on completion of the sale.

PacifiCorp’s net capital investment was £555 million for the year.

TABLE 17

PacifiCorp (£m)

2005/06 2004/05 Change

Reported operating profit 809.6 (387.3) 1,196.9

Adjustments:

IAS 39 / contracts now within the scope of IAS 39 (64.6) (0.1) (64.5)

Exceptional item — 922.0 (922.0)

Depreciation (24 May 2005 — 20 March 2006) (190.8) — (190.8)

Adjusted operating profit * 554.2 534.6 19.6

Net finance costs (178.3) (66.7) (111.6)

IAS 39 59.6 — 59.6

Adjusted net finance costs* (118.7) (66.7) (52.0)

Income tax expense (214.7) (149.7) (65.0)

Income tax on IAS 39 and depreciation 79.1 — 79.1

Adjusted income tax expense* (135.6) (149.7) 14.1

Gain on sale 619.4 — 619.4

Reported profit/(loss) for the year from discontinued operations 1,036.0 (603.7) 1,639.7

Adjusted profit for the year from discontinued operations* 299.9 318.2 (18.3)

Capital Structure, Treasury Policies & Liquidity

6.1 CAPITAL STRUCTURE

In order to provide access to international capital markets and to facilitate activities in the energy trading markets, the group’s capital structure is managed to maintain credit ratings of at least A3/A- at the regulated operating subsidiaries. The balance between debt and equity at group level is therefore set to achieve this objective although the effect of structural subordination means that the credit rating of the group’s holding companies, and the companies to which they provide credit support, will generally lie in the Baa/BBB range.

In keeping with the long-term nature of the group’s business the average maturity of the group’s debt is set at conservative levels and care is taken to ensure that maturities are well spread in order to avoid refinancing risk. As at 31 March 2006 the average maturity of the group’s debt was eight years. The same approach is applied to interest rate risk as set out below.

6.2 TREASURY POLICIES & LIQUIDITY

The treasury focus during the year continued to be to minimise interest costs and effectively manage both foreign exchange and interest rate risk whilst ensuring 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. A further priority was to maximise the return on investment of the group’s cash balances whilst avoiding excessive credit risk. All cash balances are held in sterling with the exception of approximately $75 million that is retained in the US to permit financial flexibility in relation to the operations of PPM Energy.

6.2.1 INTEREST

Reported net finance costs were £245 million for the year compared to £121 million last year. Finance income was £26 million lower at £186 million and finance costs were lower by £17 million at £316 million. IAS 39 fair value losses on financing derivatives were £115 million and primarily related to mark-to-market losses on the embedded derivative within the $700 million convertible bonds due to the company’s increased share price at the end of March 2006 compared to at 1 April 2005.

Excluding fair value losses on financing derivatives, net finance costs increased by £8 million. Underlying finance costs increased as a result of higher net debt, as the group began to utilise the proceeds from last year’s US bond issue to fund the continuing businesses’ investment activities and to make both the net equity injection into PacifiCorp and dividend payments. Net finance costs were also impacted by higher capitalised interest as a consequence of the group’s investment programme and a reduction in the unwind of discount provisions on onerous contracts as a consequence of the application of IAS 39, both of which reduced net finance costs in the Group Income Statement.

Non-GAAP performance measure (see ‘Cautionary Statement Regarding Non-GAAP Financial Information’ on page 46).

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In accordance with the group’s interest policy, the group is targeting a long-term benchmark of at least 70% fixed rate interest. As at 31 March 2006, 60% of the group’s gross borrowings were fixed for periods of more than one year, although the net position is distorted by the high surplus cash balances. Further discussion on interest rate policy is included within ‘Risk Factors’ on page 34.

6.2.2 LIQUIDITY

It is the group’s intention to pre-fund its capital expenditure programme by issuing in the global bond markets. It also retains surplus bank facilities both to provide liquidity for periods when access to bond markets may be restricted and to finance activities in energy markets.

Over the past few years the level of net debt within the group has been impacted principally by a combination of corporate transactions and the large capital expenditure programme.

As at 31 March 2006 the group had net cash and cash equivalents totalling £3,583 million although £2,250 million of that amount was held, following the sale of PacifiCorp, pending the return of cash to shareholders in June 2006.

6.2.3 BALANCE SHEET HEDGING

Following the completion of the sale of PacifiCorp on 21 March 2006, all of the cross-currency swaps hedging the net investment and the associated interest rate derivatives were cancelled. The group will continue to operate a programme to hedge the cash flows and net assets of PPM Energy, but at a substantially reduced level. As at 31 March 2006, the group had balance sheet hedges of $1,050 million (March 2005: $6.2 billion). This comprises the $700 million convertible bonds issued in 2003 and a portion of the $1.5 billion bonds issued in 2005. The remainder of the $1.5 billion bonds have been swapped into sterling.

6.2.4 CASH FLOW AND NET DEBT

Cash generated from continuing operating activities of £864 million for the year to 31 March 2006 was £183 million higher than the year to 31 March 2005, reflecting a strong operational performance in the year. Operating cash flows before working capital of £1,060 million were partly offset by working capital requirements of £196 million.

Net cash interest costs for the year were £75 million compared with net finance costs of £245 million with the difference principally reflecting £115 million of fair value losses on financing derivatives, mainly from the mark-to-market effect of the rise in the company’s share price on the embedded derivative within the $700 million convertible bonds; timing differences on the settlement of interest costs; the unwinding of discount on provisions; benefits associated with the hedging strategy and capitalised interest. Cash taxation was £75 million compared with an income tax charge of £117 million.

Net cash from operating activities was £716 million and this contributed to the funding of the group’s investment programme. Net cash provided by investing activities was £1,645 million and mainly comprised £2,768 million of net cash received from the sale of PacifiCorp, partly offset by £1,045 million of capital investment associated with the group’s investment programme and the equity investment, net of dividends, made into PacifiCorp of £174 million.

Net cash used in financing activities of £420 million largely consisted of dividend payments of £428 million and the repayment of debt of £103 million, offset by net cash from the maturing and cancellation of net investment hedges of £62 million and cash inflows of £52 million associated with share capital transactions.

As a result of the above cash flows, there was a net increase in cash and cash equivalents for continuing operations of £1,941 million from 1 April 2005 to 31 March 2006, principally reflecting the receipt of cash from the sale of PacifiCorp. After adjusting for the cash outflow

from the repayment of borrowings of £103 million and for adverse non-cash movements of £100 million, primarily relating to the effect of foreign exchange, net debt for continuing operations was £83 million at 31 March 2006, £1,944 million lower than at 1 April 2005. Excluding the proceeds from the sale of PacifiCorp, net debt would be £2,851 million, an increase of £824 million on the 1 April 2005 position. Net debt will increase significantly in June following the return of £2.25 billion of cash to shareholders and the £100 million contribution to the group’s pension schemes. The remaining net proceeds will be invested in the continuing businesses.

In addition to the cash generated from operations and existing cash balances, the group relies on flexible borrowing facilities from the capital markets, as described in the ‘Financing’ section below, at favourable rates of interest as a source of liquidity to fund investment as required. Issues of debt are influenced by levels of short-term debt, cash from operations, capital expenditure, market conditions, regulatory approvals and other considerations.

6.2.5 FINANCING

Until 2001, the group’s external borrowings were generally sourced by SPUK as the finance vehicle for the majority of the UK activities. Since then, Scottish Power plc (“SP plc”) has been the main borrower of the group.

During the year, SP plc cancelled its $375 million facility and its $625 million facility, both maturing in June 2008. These were replaced with a £500 million facility maturing in December 2010. This facility was undrawn at the year end. SP plc’s revolving credit facility contains a financial covenant limiting the ratio of consolidated borrowings to consolidated operating cash flows to no more than 4.25 to 1. The company has been in compliance with this covenant throughout the year to 31 March 2006. At no point during the year was the group in default under, or failed to satisfy any of the terms of, any of its financing arrangements and no dividends were deferred.

There have been no new issues under the SP plc $4 billion US shelf registration during the current year and there have been no new issues in the year under the group’s $7 billion euro-medium-term note programme. Cumulative issues outstanding

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under the two programmes total $1,500 million and $2,275 million respectively. SP plc and SPUK are the issuers under the euro-medium-term note programme.

During the year SPUK has not added to its index-linked liabilities, currently totalling £275 million. Total borrowings from the European Investment Bank (“EIB”) amounted to £198 million. The EIB debt within SP Manweb plc contains financial covenants relating to interest cover (EBITDA to net interest payable not less than 4.0 to 1) and net debt to EBITDA (not greater than 4.0 to 1) of SP Manweb plc. SP Manweb plc has been in compliance with these covenants throughout the year to 31 March 2006.

The UK distribution, transmission and generation subsidiaries have provided upstream guarantees to support the majority of SPUK’s debt that existed at 1 October 2001, following their incorporation to comply with the Utilities Act 2000 (“Utilities Act”). As at 31 March 2006, the total amount of debt guaranteed by the three companies amounted to £1,959 million. New debt issued by SPUK after 1 October 2001 is not permitted to benefit from the guarantee of SPUK’s subsidiaries, SP Distribution Limited and SP Transmission Limited.

PPM Energy is funded by loans from other group companies and does not hold any external debt, although certain power purchase obligations relating to the Klamath project are accounted for as debt on the Balance Sheet. As part of the financing structures to enable PPM Energy to utilise the benefits of PTCs going forward (see Section 4.3 ‘PPM Energy’), the group may expect to realise accelerated cash receipts against any debt or financing requirements as part of these financing structures.

6.2.6 CREDIT RATINGS

SP plc and SPUK have credit ratings published by Standard & Poor’s Ratings group (“S&P”) and Moody’s Investors Service (“Moody’s”) as shown in Table 18. These security ratings are not recommendations to buy, sell or hold securities. The ratings are subject to change or withdrawal at any time by the respective credit rating agencies. Each credit rating should be evaluated independently of any other rating.

TABLE 18

Credit ratings

S&P Moody’s

SP plc BBB+ Baa1

SPUK (long-term) A- A3

SPUK (short-term) A-2 P-2

Any adverse change to credit ratings of group companies could negatively impact on their ability to access capital markets and on the rates of interest that they would be charged for such access. The EIB debt within SP Transmission Limited and SP Distribution Limited contains credit downgrade language, which does not constitute default, but means that, should the ratings of SP Transmission Limited or SP Distribution Limited fall, the EIB will be entitled to ask for additional security in the form of a guarantee acceptable to the EIB. Interest rates under SP plc’s

revolving credit facility and commitment fees on the facility would both increase with a ratings downgrade.

The investment of surplus cash is undertaken to maximise the return within Board-approved policies, which govern the ratings criteria, maximum investment and the maturity with any one counterparty. Counterparties are required to have a short-term rating of at least A-1, P-1 or F-1 from one of the three major rating agencies.

As set out above, ScottishPower is committed to maintaining an A category credit rating for its regulated operating subsidiaries, thereby allowing access to flexible borrowing sources at favourable cost. To achieve this rating, the group will target credit ratios of adjusted FFO/net debt of greater than 25% and FFO/interest cover of more than five times. ScottishPower will work closely with the rating agencies in order to ensure its rating objectives are achieved.

6.2.7 CONTRACTUAL OBLIGATIONS AND

COMMERCIAL COMMITMENTS

The group enters into various financial obligations in the normal course of business. Contractual financial obligations are considered to comprise known future cash payments that the group is required to make under contractual arrangements in place at 31 March 2006.

Table 19 details the group’s contractual obligations at 31 March 2006.

TABLE 19

Contractual obligations at 31 March 2006 (£m)

Payments due by period

Less than 1-3 3-5 More than

year years years 5 years Total

Loans and other borrowings

(including overdrafts) 700.3 789.5 962.4 2,934.1 5,386.3

Finance leases 13.2 26.9 25.2 27.3 92.6

Operating leases 10.8 16.4 10.9 67.6 105.7

Energy purchase commitments 3,842.7 2,672.1 982.4 1,913.8 9,411.0

Capital commitments 361.6 170.5 – – 532.1

Other firm commitments 51.6 78.3 65.0 48.2 243.1

Total 4,980.2 3,753.7 2,045.9 4,991.0 15,770.8

In addition to the contractual obligations in the table above, the group expects to contribute £146 million to its UK pension schemes (including one-off special contributions of £100 million) in the year ending 31 March 2007.

The loans and other borrowings figures in Table 19 are stated at book value at 31 March 2006 and include future interest payments under these obligations as well as interest commitments on the group’s treasury-related derivatives.

Energy purchase commitments included within Table 19 arise principally from short- and long-term power and fuel purchase contracts.

Other firm commitments included within Table 19 arise principally from operations and maintenance contracts and information technology services.

The group invested £1 billion in its asset base during the year ended 31 March 2006. The group’s estimated net investment in its

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TABLE 20

Fair value of financial derivative contracts (£m)

Total group

Fair value of contracts outstanding at 1 April 2005 545.2

Contracts realised or otherwise settled during the year (98.2)

Changes in fair values attributable to changes in valuation techniques and assumptions —

Other changes in fair value 445.8

Foreign exchange movement 0.8

Fair value of contracts outstanding at 31 March 2006 893.6

asset base for the year ended 31 March 2007, which is subject to continuing review and revisions, is approximately £1.2 billion, based on a US dollar/UK sterling exchange rate of approximately $1.80, and represents investment in growth projects and refurbishment.

6.3 GOING CONCERN

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

Fair Value of Derivative

Contracts, Pension & Off Balance Sheet Arrangements

7.1 FAIR VALUE OF DERIVATIVE CONTRACTS

The group uses derivative instruments in the normal course of business to offset fluctuations in earnings, cash flows and equity associated with movements in exchange rates, interest rates and commodity prices. Table 20 details the changes in the fair value of the group’s energy related and treasury derivative contracts which are subject to the requirements of IAS 39. IAS 39 requires all derivatives, as defined by the standard, to be marked to market, except for those which qualify for a specific exemption under the standard or associated guidance, for example those defined as own use. The derivatives which are marked to market in accordance with IAS 39 include only certain of the group’s commercial contractual arrangements as many of these arrangements fall outside the scope of IAS 39. The group has entered into various energy-related and treasury derivative contracts, primarily for hedging purposes. In accordance with IFRS, the value of derivatives are reflected as assets or liabilities at their fair values at the balance sheet date, with changes in fair values of those derivatives held for hedging purposes only recognised through earnings when the hedged item is recognised.

The group’s valuation strategies for derivative and other financial instruments utilise as far as possible quoted prices in an active trading market. Futures, swaps, and forward agreements

TABLE 21

Maturity profile of fair value of derivative contracts outstanding (£m)

Within Between Between After

year 1-3 years 3-5 years 5 years Total

Valuation based on actively quoted market prices and rates from third-party sources 291.3 222.9 10.0 20.0 544.2

Valuation based on models and other valuation methods 149.6 202.1 32.8 (35.1) 349.4

Total 440.9 425.0 42.8 (15.1) 893.6

are valued against the appropriate market-based curves. Forward price curves are developed using market prices from independent sources for liquid commodities, markets and products and modelled for illiquid commodities, markets and products. Single-variable options are valued against market price and volatility curves. Dual-variable options are valued against market price, volatility and correlation curves between two variables. Volatility curves are developed for open positions in both liquid and illiquid markets. They are developed from actively traded options (implied volatility), where markets exist, or using historical forward volatilities and other relevant market data. Correlation curves are developed using historical spot and forward correlations and other relevant market data. Structured transactions are disaggregated into their traded core components, and each component is valued against the appropriate market-based curves. For transactions where a market price for the point of delivery is not actively quoted, if possible, the transaction is valued at the most appropriate point of delivery where a market price exists with appropriate adjustments for the actual point of delivery, including if applicable currency adjustments. Assets owned (long position) are valued against the quoted bid price. If assets are owed (short position) they are marked to the quoted offer price. Where valuation incorporates midmarket price data, additional liquidity adjustments are made to the fair value to bring it in accordance with the profile of net long/short exposure. The value of net long volatility positions is marked against the bid volatility curve. For net short volatility positions, the offer volatility curve is used. Other adjustments include discounting and credit adjustments, where those have not already been captured in the mark-to-market process. In the absence of quoted prices for identical or similar assets or liabilities, it is sometimes necessary to apply valuation techniques where contracts are marked to approved models. Models are used for developing both the forward curves and the valuation metrics of the instruments themselves where the instruments are complex combinations of standard or nonstandard products. All models are subject to rigorous testing prior to being approved for valuation and subsequent

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continuous testing and approval procedures designed to ensure the validity and accuracy of the model assumptions and inputs.

The group accounts for compound financial instruments that contain both a liability and an embedded derivative component by separating these components and assigning individual values to each of them. In Table 20 changes in fair values attributable to changes in valuation techniques and assumptions reflect changes in the fair value of mark-to-market values as a result of applying refinements in valuation modelling techniques. Other changes in fair value reflect changes in fair value that have been recognised through the income statement or through equity in the current year in relation to derivative financial instruments.

As shown in Table 21, standardised derivative contracts that are valued using market quotations are classified as valuations based on actively quoted market prices and rates from third-party sources. All remaining contracts, which include non-standard contracts and contracts for which market prices are not routinely quoted, are classified as valuations based on models and other valuation methods.

7.2 PENSION ARRANGEMENTS

The group accounts for its retirement benefit obligations in accordance with IAS 19 (“Employee Benefits”). IAS 19 prescribes detailed rules for the calculation of pension scheme assets and liabilities and indicates the net accounting surplus or deficit that would exist on an ongoing basis using market conditions at the balance sheet date. Fluctuations in market conditions can result in significant volatility in the balance sheet position. Pension schemes are, however, managed over the long-term. Investment and liability decisions are based on underlying actuarial and economic circumstance with the intention of making sure that the schemes have sufficient assets to meet liabilities as they fall due, rather than meeting accounting requirements. The group and the trustees of the group’s schemes have reviewed the investment strategy for the asset/liability matching of the group’s schemes and this has resulted in agreement to a gradual shift towards a higher element of bond/gilt holdings from equities. While the trustees of each plan are responsible for determining investment strategy they do liaise with and keep the company informed of their strategy. The ongoing position will continue to be monitored by the trustees and the company. The objective over the long-term being to make sure the investment strategy is aligned to the maturing nature of the scheme and its liabilities.

At 31 March 2006, the group’s retirement benefit obligations in respect of pensions amounted to £153 million (2005: £502 million). In connection with the return of cash to shareholders, the group has reached agreement with the trustees of the ScottishPower Pension Scheme, the ScottishPower Group Final Salary LifePlan and the Manweb Group Section of the Electricity Supply Pension Scheme to make special contributions to each scheme in order to fund the deficit as at 31 December 2005, computed in accordance with Financial Reporting Standard 17 (“Retirement Benefits”), in respect of each scheme over a period of up to five years. The group has made an aggregate lump sum contribution of £28 million during March 2006 into the schemes. On completion of the return of cash to shareholders, an aggregate lump sum contribution of £100 million will be made to the schemes and four further aggregate annual payment of £13.2 million will be made to the schemes commencing on 31 March 2007, subject to a deficit continuing in those schemes at each due payment date. The pension cost recognised in the year ended 31 March 2006 amounted to £68 million (2005: £48 million) of which £49 million (2005: £28 million) related to continuing operations and £19 million (2005: £20 million)

to discontinued operations. These amounts are stated before capitalisation of employee costs in respect of self-constructed assets.

Following a review of the group’s UK pension arrangements, the ScottishPower Final Salary LifePlan and the ScottishPower Executive Top up Plan were merged with the ScottishPower Pension Scheme as at 31 March 2006. This will lead to economies of scale in relation to the ongoing running costs in the delivery of the pension benefits due to the group’s current and past staff. From 1 April 2006 new entrants will have access to a defined contribution Stakeholder Pension Plan. The merged ScottishPower Pension Scheme and the Manweb Pension Scheme are closed to new entrants.

7.3 OFF BAL ANCE SHEET ARRANGEMENTS

The group has not entered into any transactions or arrangements which have given rise to off balance sheet obligations other than in respect of the following:

7.3.1 OPERATING LEASES

The group has entered into various operating leases. In accordance with IFRS, future payments under these leases, amounting to £106 million at 31 March 2006 (2005: £97 million), are not recognised as liabilities in the group’s balance sheet.

7.3.2 GUARANTEES

In the course of its ordinary business, the group has provided certain guarantees of its own performance. These guarantees are not expected to have a material impact on the group’s financial position. In addition, in accordance with common practice, the group has provided guarantees of the performance of certain businesses and assets, which have been disposed of. The group has provided for a liability, estimated at $170 million, under the tax indemnity given to MidAmerican on the sale of PacifiCorp. As a result of the sale of PacifiCorp, the US tax group holds sufficient capital losses to offset this liability. With this exception, the amounts guaranteed under these arrangements are significant in absolute value but the probability of these guarantees crystallising and resulting in a material change in the group’s financial position is remote. The group has also entered into other arrangements in the normal course of business, which may crystallise as a result of events other than the group’s non-performance of its contractual obligations. The

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probability of these guarantees giving rise to a material change in the group’s financial position is remote. Further details of these guarantees are provided in Note 44(k) on page 152.

IFRS to US GAAP Reconciliation

The group’s Accounts are prepared in accordance with IFRS, which differs in significant respects from US GAAP.

Reconciliations of profit and equity shareholders’ funds between IFRS and US GAAP are set out in Note 44 to the Accounts. Under US GAAP, the profit for the year ended 31 March 2006 was £1,085.4 million, compared to a loss of £494.7 million in the previous year. The earnings per share under US GAAP was 58.91 pence compared to a loss per share of 27.02 pence in 2004/05. Equity shareholders’ funds under US GAAP amounted to £5,520.9 million at 31 March 2006 compared to £4,794.2 million at 31 March 2005.

9 Resources, Relationships

& Risk Factors

REPORTING OF NON-FINANCIAL MEASURES

Note: For the first time, reporting of the group’s results is covered by the EU Accounts Modernisation Directive (“AMD”). The AMD has implications for the reporting of non-financial aspects of the group’s performance. Since 1995, ScottishPower has published an annual summary of environmental impacts to air, land, water and biodiversity which from 2002/03, has been contained in the ScottishPower Environmental and Social Impact Report (and the related detailed performance reports), published in the autumn of each year. Implementation of the AMD has been the subject of extensive consultation and uncertainties remain regarding aspects of emerging best practice. ScottishPower is conducting a review of its non-financial reporting and will publish its full disclosure in respect of Corporate Responsibility matters on the ScottishPower website in the autumn of 2006. From 2005/06, the group’s environmental reporting will be consistent with the UK Government’s Department of Environment Food and Rural Affairs Guidelines for Environmental Reporting. In the meantime, a high level selection of Key Performance Indicators (“KPI”) and summary data is included in this section of the Annual Report & Accounts.

9.1 RESOURCES

9.1.1 DESCRIPTION OF THE COMPANY’S PROPERTY

UK BUSINESSES

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

ScottishPower owns seven power stations in Scotland (five of which are operational) and four in England. It also owns four windfarms in Northern Ireland, six in Scotland, and one in the Republic of Ireland. In addition, the company has joint venture interests in four windfarms, three of which are in England and one in Wales. All generation plant is owned by the company, with the exception of the non-operational 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 22 for details of operational generation assets.

At 31 March 2006, the UK transmission facilities included approximately 4,000 circuit km of overhead lines and underground cable operated at 400 kV, 275 kV and 132 kV. In addition, the distribution facilities included approximately 108,000 circuit km of overhead lines and

underground cable at voltages operating from 33 kV to 0.23 kV. The group holds either permanent rights or wayleaves which entitle it to run these lines and cables through private land. See Table 9 (page 14) for further details.

NORTH AMERICAN BUSINESS

The North American properties consist primarily of generating facilities, gas storage facilities and a number of offices.

PPM Energy owns or controls more than 2,200 MW of generating capacity, including power purchase and operating agreements, see Table 23.

PPM Energy’s contracted capacity (606 MW of wind power contracted for a period of 25 years and 237 MW of thermal power contracted for a period of 30 years) comes from long-term agreements while 1,099 MW comes from outright ownership of 12 wind plants and two thermal plants. PPM Energy’s windfarms are on land owned or leased for 25 years or more. PPM Energy also manages group-owned gas storage facilities in Alberta, Canada and owns facilities in Texas and New Mexico, representing about 50 BCF of gas storage capacity.

9.1.2 GROUP EMPLOYEES

ScottishPower and its subsidiaries had 9,793 employees as at 31 March 2006. Of these, 3,380 were employed in Energy Networks, 5,512 in Energy Retail & Wholesale, and 371 in PPM Energy and its subsidiaries, with the remaining 530 employed in corporate services and other US subsidiaries. Approximately 57% of employees in the UK are union members, and 82% are covered by collective bargaining arrangements. In the company’s judgement, employee relations in both the UK and the North American businesses are satisfactory.

EMPLOYMENT REGULATION

Formal terms of employment for ScottishPower employees vary across the group as they reflect local employment legislation – which varies not just between the UK, Canada and the US, but between different US states. ScottishPower has well-defined policies in place throughout its businesses to ensure compliance with applicable laws and related codes of practice. These policies cover a wide range of employment issues such as disciplinary action, grievance, harassment, discrimination, stress and ‘whistle-blowing’ and have been brought together in the ScottishPower policy document, ‘Compliance – Behaviour and the Law’ (which also outlines expectations for employees’ conduct).

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TABLE 22

Sources of ScottishPower owned generating capacity and output in the UK and the Republic of Ireland as at 31 March 2006

Plant net capability (MW)

Installation date

Location

Energy source

Thermal electric plants

Longannet Fife, Scotland Coal/gas/waste derived fuel 1970 2,304

Cockenzie East Lothian, Scotland Coal/oil/biomass 1967 1,152

Brighton Sussex, England Natural gas-fired – combined cycle 2000 400

Damhead Creek Kent, England Natural gas-fired – combined cycle 2000 800

Knapton Yorkshire, England Sour gas-fired – single open cycle 1994 42

Rye House Hertfordshire, England Natural gas-fired – combined cycle 1993 715

Sub-total (6 thermal electric plants) 5,413

Hydroelectric plants

Cruachan Argyll & Bute, Scotland Pumped storage 1965 440

Galloway Scheme Dumfries & Galloway, Scotland Conventional hydro 1930s/1985 106

Lanark Scheme Lanarkshire, Scotland Conventional hydro 1920s 17

Sub-total (3 hydroelectric plants) 563

Renewable electric plants

Barnesmore County Donegal, Republic of Ireland Wind generation 1997 15

Beinn an Tuirc Argyll & Bute, Scotland Wind generation 2001 30

Black Law Lanarkshire, Scotland Wind generation 2005 97

Callagheen County Fermanagh, Northern Ireland Wind generation 2006 17

Carland Cross Cornwall, England Wind generation 1992 3*

Coal Clough Lancashire, England Wind generation 1992 4*

Coldham Cambridgeshire, England Wind generation 2005 16*

Corkey County Antrim, Northern Ireland Wind generation 1994 5

Cruach Mhor Argyll & Bute, Scotland Wind generation 2004 30

Dun Law Midlothian, Scotland Wind generation 2000 17

Elliots Hill County Antrim, Northern Ireland Wind generation 1995 5

Hagshaw Hill Lanarkshire, Scotland Wind generation 1995 16

Hare Hill Ayrshire, Scotland Wind generation 2000 13

P & L Windfarm Monmouthshire, Wales Wind generation 1993 15*

Rigged Hill County Londonderry, Northern Ireland Wind generation 1994 5

Sub-total (15 renewable electric plants) 288

CHP Various, England Combined heat and power (gas fired) Various 102

Total all plants (owned or controlled plants) 6,366

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

EMPLOYEE CONSULTATION

The group’s businesses use surveys and other tools to understand the key issues for each business unit. Regular consultation takes place using a variety of means, including monthly team meetings, team managers’ conferences, business unit road shows, safety committees, presentations and employee magazines. The group believes that an important element of a positive working experience is stable employee and industrial relations; it recognises the legitimacy of trade union involvement and has formal agreements in place to foster open, two-way communication and consultation. Positive relationships and ongoing liaison with employees and their representatives are seen as contributing significantly to achieving the performance objectives of the businesses.

The company has also undertaken a review of its existing UK consultation arrangements in order to comply with the Information and Consultation of Employees Regulations which came into force in April 2005. These Regulations give employees in larger firms the right to be informed and consulted on a regular basis about issues in the business they work for.

EQUAL OPPORTUNITIES

ScottishPower is committed to promoting equal opportunities for all, irrespective of age, colour, disability, ethnic or national origin, marital status, nationality, race, religion or similar belief, creed, sex, sexual orientation or any other considerations that do not affect a person’s ability to perform their job.

In recruitment the group aims to employ the best candidate for a job, irrespective of gender, race, disability or any other status protected by relevant laws.

Further details of group workplace policy and performance can be found in the ‘Corporate Responsibility’ section of www.scottishpower.com.

9.1.3 RESEARCH AND DEVELOPMENT

ScottishPower supports research into development of the generation, transmission, distribution and supply of electricity. It also continues to contribute, on an industry-wide basis, towards the cost of research into electricity utilisation and distribution developments. In financial years 2005/06, 2004/05 and

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TABLE 23

Summary of PPM Energy generating facilities as at 31 March 2006

Plant net capability (MW)

Installation date

Location

Energy source

Thermal electric plants

Klamath Cogeneration Plant Klamath Falls, Oregon Natural gas-fired – combined cycle 2001 506†

West Valley Generating Plant West Valley City, Utah Natural gas-fired – single cycle 2002 200

Klamath Generating Plant Klamath Falls, Oregon Natural gas-fired – single cycle 2002 100

Sub-total (3 thermal electric plants) 806

Renewable electric plants

Phoenix Wind Power Plant Southern California Wind generation 1999 3

Stateline Wind Energy Center Oregon/Washington Wind generation 2002 300

Klondike Wind Power Plant North Central Oregon Wind generation 2001 24

Klondike II Wind Power Plant North Central Oregon Wind generation 2005 75

High Winds Energy Center Northern California Wind generation 2003 162

Southwest Wyoming Wind Energy Center Southwest Wyoming Wind generation 2003 144

Moraine Wind Power Plant Southwest Minnesota Wind generation 2003 51

Flying Cloud Wind Power Plant Northwest Iowa Wind generation 2003 44

Mountain View III Wind Power Plant Southern California Wind generation 2003 22

Colorado Green Wind Power Plant Southeast Colorado Wind generation 2003 81*

Trimont Wind Power Plant Southwest Minnesota Wind generation 2005 100

Elk River Wind Power Plant Central Kansas Wind generation 2005 150

Maple Ridge Wind Farm Upstate New York Wind generation 2005 99*

Shiloh Wind Power Plant Northern California Wind generation 2006 150

Sub-total (14 renewable electric plants) 1,405

Total all plants (owned or controlled plants) 2,211

† Third-party owned plant; PPM Energy has a contract for 47% of the output; and provides management services to the third-party for the full output.

Jointly owned plants; amount shown represents PPM Energy’s share only.

2003/04, research and development expenditure charged to the group’s operating profit was £0.3 million, £0.2 million and £0.2 million, respectively.

9.2 REL ATIONSHIPS

9.2.1 COMMUNITY

MANAGING IMPACTS THROUGH COMMUNITY CONSULTATION

Key community impact issues include the siting of new facilities, the presence of distribution and transmission lines and routine maintenance and upkeep work. A variety of methods of consultation is used to keep in touch with the needs and concerns of the communities potentially affected.

In the UK community consultation processes include representation at community meetings, presentations and forums, for example, consultation is part of the windfarm development process, from scoping through to the end of development. Maintenance work often involves gaining access and working on other people’s land, so a Grantor’s Charter is employed, which details standards staff and contractors observe when working on other people’s property.

PPM Energy is making substantial investment in new windfarm facilities and has developed a comprehensive process for evaluating the community impact of windfarms, including surrounding environment, consistent with current land uses and impacts on wildlife.

INVESTING IN THE COMMUNITY

In order to encourage comparability, the group uses the London Benchmarking Group (“LBG”) model to evaluate its community support activity across the group. The LBG model is a standard

for community reporting currently adopted by 101 leading UK companies. It endeavours to provide consistency and comparability across companies and to account for the total impact on communities, rather than charitable contributions alone. ScottishPower’s use of the model is reviewed each year by the LBG to help ensure the evaluation principles are correctly and consistently applied.

During 2005/06, ScottishPower companies contributed £3.83 million in community support activity, of which £1.80 million was contributed to registered charitable organisations. The total incorporated £631,000 categorised by the LBG model as charitable gifts, £2.98 million of community support activity categorised as community investment and £218,000 categorised as commercial initiatives in the community given in cash, through staff time and in-kind donations.

Further details of group community engagement policy and performance in the ‘Corporate Responsibility’ section of www.scottishpower.com.

9.2.2 CUSTOMERS

Customers’ most fundamental requirements are the provision of a safe, reliable supply of energy and responsive, effective attention when they contact the group’s businesses.

SYSTEM PERFORMANCE

In the UK, Ofgem sets targets for system performance, monitoring the two key indicators: CML and CI. Table 24 shows the Energy Networks performance on these measures, indicating

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TABLE 24

Energy Networks system performance

Customer Minutes Lost 2005/06 2004/05

SP Distribution 66.8 74.9

SP Manweb 57.4 65.2

Customer Interruptions 2005/06 2004/05

SP Distribution 57.6 65.0

SP Manweb 42.7 49.0

CUSTOMER SATISFACTION AND COMPL AINTS

Energy Networks

Complaints to the independent industry consumer watchdog, energywatch, dropped from 111 in 2004/05 to 96 in 2005/06. Penalties were avoided in Ofgem’s telephone answering initiative but rankings against other licensees placed ScottishPower 11th and Manweb 12th out of 14. A working group is currently delivering a number of initiatives intended to improve this performance.

Energy Retail

Energy Retail performance is monitored against targets set by Ofgem for Guaranteed Standards (see Table 25) and is also judged by complaints to energywatch per 1,000 customers, which were 1.62 in 2005/06 (2004/05: 1.57). However, in April 2005 energywatch filed a super-complaint requiring Ofgem to investigate suppliers’ handling of fuel bills and ScottishPower is working with others to address the concerns raised about the industry-wide billing performance.

TABLE 25

Guaranteed standards

Supply and Metering UK 2005/06 2004/05

Timely repair of faulty prepay meters 98.34% 98.49%

Timely despatch of compensation payments 96.70% 98.57%

Timely repair of faulty domestic meters 99.93% 99.92%

Timely response to questions 99.97% 98.97%

Appointments kept to time slot 98.93% 98.81%

Further details of the group’s system delivery, complaints and other satisfaction measures can be found in the ‘Corporate Responsibility’ section of www.scottishpower.com.

TABLE 27

Continuing businesses power plant emissions KPIs

Total kTonnes GWh production kTonnes per GWh

Emissions 2005 2004 2005 2004 2005 2004

Greenhouse gases

Carbon dioxide 15,448 15,732 27,230 24,649 0.5673 0.6383

Acid rain and smog precursors

Sulphur dioxide 48 62 27,230 24,649 0.0014 0.0025

Oxides of nitrogen 34 34 27,230 24,649 0.0012 0.0014

9.2.3 THE ENVIRONMENT

ScottishPower acknowledges its responsibility for managing the impacts of the group’s activities in the production, distribution and supply of energy in an environmentally responsible manner.

ENERGY GENERATION, CLIMATE CHANGE AND

EMISSIONS TO ATMOSPHERE

Part of the group’s response to managing environmental risk and to the challenge of climate change is to manage the balance of its energy generation: from coal-burning (which of all commercial options produces the highest levels of CO2) to gas-burning (which produces about half as much CO2 as coal) and renewables (which produce little to no CO2). The changing mix of the group’s continuing businesses’ electricity generation portfolio, is shown in Table 26. This reflects the purchase and construction of new gas-fired power stations and the increased focus on renewable energy across the group.

TABLE 26

Continuing businesses energy generated or controlled by fuel type

Percentage generation mix

Fuel Type (%) 2005 2004

Coal 42.4 45.0

Gas 43.6 41.6

Hydro 1.8 2.2

Wind 10.1 10.5

Other 2.2 0.6

During 2005, ScottishPower was required to comply with the new regulations applicable to the EU’s Emissions Trading Scheme (“ETS”). As part of these regulations, the company was required to redeem emissions allowances to account for greenhouse gas emissions from thermal coal and gas fired generating stations and CHP plant in the UK. The company has met its obligation for the EU emissions year January to December 2005, with the surrender of 15 million tonnes of CO2 emission allowances in relation to 15 million tonnes of CO2 emissions.

ScottishPower is also required to comply with the UK Government’s RO, under which a proportion of the electricity supplied to customers must be certified from renewable sources. For the last full reporting period (2004/05), ScottishPower redeemed 73% of its obligation.

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Burning fossil fuels to generate electricity produces both CO2 and other gases that are potentially harmful to the environment, including sulphur dioxide (“SO2”) and oxides of nitrogen (“NOX”), along with small quantities of heavy metals in combustion ash.

Table 27 sets out the CO2, SO2 and NOX power plant emissions of the group’s continuing businesses.

ENERGY INFRASTRUCTURE – TRANSMISSION AND

DISTRIBUTION

Energy infrastructure development requires the enhancement and maintenance of the networks and has associated environmental impacts. These impacts are mostly focused on special planning, biodiversity management and management of waste.

ENERGY EFFICIENCY AND DEMAND SIDE MANAGEMENT

Helping customers to become more efficient reduces their energy costs and helps improve environmental performance. In the UK, Ofgem sets residential energy efficiency targets, the EEC, for all licensed suppliers. During the year, ScottishPower has commenced the second phase of EEC which is scheduled to continue until March 2008.

LAND AND BIODIVERSITY

The potential effect of facilities and infrastructure on land and biodiversity has prompted an approach to habitat management that often goes beyond regulatory requirements. This has been developed in consultation with regulatory bodies, nongovernmental organisations, wildlife and special interest groups. The aim is not only to minimise impact on natural habitats from the group’s operations but to improve upon them, at existing and planned developments, and at sites where activities have ceased. In particular, during 2005/06, Energy Wholesale has implemented a Windfarm Sustainable Development policy in respect to site selection and management.

Similarly in the US, PPM Energy makes significant efforts to protect wildlife in the siting, construction, and operation of its wind business pursuant to a revised Wind Siting and Avian Policy. In addition, PPM Energy has contributed to selected research projects to study the interaction of birds and bats with windfarms, and taken a leading position in numerous multi-stakeholder processes to develop new wind energy/wildlife guidelines.

TABLE 28

Lost Time Accident rates

Numbers of accidents Accidents per 100 employees

Business 2005/06 2004/05 2005/06 2004/05

Energy Networks 11 10 0.41 0.38

Energy Retail 14 22 0.30 0.49

Energy Wholesale 4 2 0.41 0.21

PPM Energy — — — —

Corporate and other — 2 — 0.42

Total for continuing operations 29 36 0.32 0.41

CONTAMINATED LAND

The ScottishPower policy on Contaminated Land includes a number of activities to help identify, assess, control and remediate the risks of land or property contamination. Each business

operation has active programmes of investigation taking place on an ongoing basis. During 2005/06, the company has identified no new material assets that require remedial activity.

COMPLIANCE PERFORMANCE

ScottishPower and its subsidiary companies undertake all operational activities in accordance with relevant environmental permits and authorisations. During 2005/06, the group suffered no (2004/05: nil) prosecutions or fines for breaches of environmental requirements and was issued with two notices of non-compliance (2004/05: three).

Further details of group environmental policy and performance can be found in the ‘Corporate Responsibility’ section of www.scottishpower.com.

9.2.4 HEALTH AND SAFETY

Health and Safety governance is led by the Chief Executive with the ScottishPower Executive Team (“ET”) approving groupwide health and safety targets and reviewing health and safety performance. Monitoring of performance is based on the Group Health and Safety Framework. There are 12 health and safety standards that are used to provide regular assurance to the Board, ET and employees that health and safety is managed effectively and in line with policy. Challenging targets are set each year on lost time accident (“LTA”) rates and leading indicators based on the health and safety standards.

The group has a clear strategy to continue to improve health and safety performance using the group health and safety standards.

It has now completed the third year of assessments against these standards and has made significant improvements that correlate well with continuing reductions in LTA rates.

The group LTA rate fell from 0.41 to 0.32 per 100 employees. Details by business are shown in Table 28.

During 2005/06 there has been a focus on training managers and team leaders to enhance their ability to manage health and safety, further enhancing employee training and continuing to promote wider employee involvement in health and safety.

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9.2.5 POLITICAL DONATIONS AND EXPENDITURE

ScottishPower is a politically neutral organisation. The company is subject to the Political Parties, Elections and Referendums Act 2000 which defines political “donations” and “expenditure” in wider terms than would be commonly understood by these phrases. The definitions include expenditure which the Board believes it is in the interests of the company to incur. The Act also requires companies to obtain prior shareholder approval of this expenditure; at the AGM in 2005 the company obtained authorisation up to a maximum amount of £80,000 for donations and £20,000 for expenditure.

During the financial year, the company paid a total of £30,550 for activities which may be regarded as falling within the terms of the Act. The recipients of these payments were:

The Labour Party £21,500;

The Conservative and Unionist Party £2,000;

Liberal Democrats £3,300; Scottish National Party £2,750; and

Plaid Cymru £1,000.

These activities comprised the sponsorship of briefings and receptions at party conferences and attendance at party events. These occasions provide an important opportunity for the company to represent its views on a non-partisan basis to politicians from across the political spectrum. The payments do not indicate support for any particular party.

9.2.6 REGUL ATION

DESCRIPTION OF LEGISLATIVE AND REGULATORY

BACKGROUND

As a public limited company (“plc”), Scottish Power plc is subject to the UK Companies Acts and, as a holding company for PPM Energy, is subject to Federal Energy Regulatory Commission (“FERC”) regulation as to books and records under the US Public Utility Holding Company Act of 2005.

The principal pieces of legislation forming the regulatory framework for ScottishPower’s UK operations are the Electricity Act, the Gas Act 1986 and the Gas Act 1995 (“the Gas Acts”) as amended by the Utilities Act, the Energy Act 2004 (“Energy Act”) and the relevant EU Directives and Regulations.

The Utilities Act introduced a legal framework for energy company licences based on standard, GB-wide conditions and, taken together with requirements of the Department of Trade and Industry (“DTI”) and licence changes introduced by the Regulators, defines the regulatory framework within which SPUK’s electricity and gas businesses must operate. In addition, SPUK must act in compliance with EU and UK competition law, in particular, Articles 81 and 82 of the EC Treaty, the Competition Act 1998 and the Enterprise Act 2002.

PPM Energy’s wholesale activities are primarily regulated by the FERC, which has authorised market-based rates for PPM Energy and many of its subsidiaries. In addition, PPM Energy’s gas storage activities in Texas and New Mexico are subject to regulation by the FERC and by the Texas Railroad Commission and the New Mexico Energy, Minerals and Natural Resources Department, respectively. Those in Canada are subject to regulation by the Alberta Energy and Utilities Board.

UK ELECTRICITY AND GAS INDUSTRY REGULATION

The Utilities Act transferred the functions of the previous electricity and gas industry regulators to the Authority, provided for the appointment of a Chairman and other members of the Authority by the Secretary of State for Trade and Industry (“Secretary of State”). The

administrative body supporting the Authority is Ofgem, and the Chief Executive of the Authority is also the Chief Executive 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 electricity and gas are met; the need to ensure that licence holders are able to finance their functions; and 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 Office of Fair Trading (“OFT”), certain functions relating to merger control and anti-competitive conduct and also in relation to UK compliance with the EU’s regulatory framework, which has sought to introduce competition in generation and supply and non-discriminatory access to gas transportation and electricity transmission and distribution across the EU.

The Authority is responsible for granting new licences or licence extensions for each participant in the GB gas and electricity markets. The group is required by legislation to hold various licences and, through its relevant operating subsidiaries, is licensed to operate over 6,300 MW of generating capacity and, by contracting in the wholesale market, has access to capacity operated by other licensed generators; to own and maintain the transmission system in central and southern Scotland; to distribute electricity within its two distribution services areas for all suppliers whose customers are within the areas; to contract with gas transporters to have gas transported between the beach terminal and the point of supply; and to supply gas and electricity to customers, with the associated customer service activities, including customer registration, meter reading, sales and marketing, billing and revenue collection.

The Authority is also responsible for monitoring compliance with the conditions of licences and, where necessary, enforcing them through procedures laid down in the Electricity and Gas Acts. Under these Acts, as amended by the Utilities Act, licences consist of standard licence conditions, which apply to all classes of licences, and special conditions particular to that licence. The Authority may modify licence conditions by agreement or through a modification reference to the Competition Commission which requires the Competition Commission to investigate and report on whether matters specified in the reference in pursuance of a licence modification operate, or may be expected to operate, against the public

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interest; and, if so, whether the adverse public interest effect of these factors could be remedied or prevented by modification of the conditions of the licence. If the Competition Commission so concludes, the Authority must then make such modifications to the licence as appear to it requisite for the purpose of remedying or preventing the adverse effects specified in the report, after giving due notice and consideration to any representations and objections. The Competition Commission has the power to veto any modification. Licences may be terminated in accordance with the licence conditions (for the major licences, by not less than 25 years’ notice given by the Secretary of State) and may be revoked in certain circumstances specified in the licence. These include the insolvency of the licensee, the licensee’s failure to comply with an enforcement order made by the Authority and the licensee’s failure to carry on the activities authorised by the licence.

The UK regulatory regime recognises that the development of competitive markets is not appropriate in some areas: particularly in the core activities of transmission and distribution of electricity and the operation of the gas transportation system. In these areas, regulatory controls are deemed necessary to protect customers in monopoly markets (by determining inflation-limited price caps) and to encourage efficiency. The group’s UK transmission and distribution businesses are subject to price controls which restrict the average amount, or total amount, charged for a bundle of services. Through participation in, and the submission of evidence to, price control reviews companies have the opportunity to comment on and seek to influence the final outcome of any price control review.

FERC MARKET POWER ANALYSIS

PPM Energy is authorised by the FERC to charge market-based rates for sales of wholesale energy and capacity. Under the FERC’s current policy, market participants must demonstrate that they do not possess market power and are required to submit a market power analysis every three years. The analysis must be applied to all affiliated entities on a combined, or aggregate, basis. In February 2005, PPM Energy and its then affiliate, PacifiCorp, submitted their joint triennial market power analysis to the FERC, which instituted a proceeding to determine whether PPM Energy and PacifiCorp may continue to charge market-based rates for sales of wholesale energy and capacity. The FERC has requested additional information and analysis most recently a submission required by 29 March 2006 and has continued to require market power analysis, even though the sale of PacifiCorp has completed.

UK ENVIRONMENTAL REGUL ATION

bodies such as the United Nations Economic Commission for Europe. 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.

The Electricity Act obligates the Secretary of State to take into account the effect of electricity generation, transmission, distribution and supply activities upon the physical environment in approving applications for the construction of generating facilities and the location of overhead power lines. The Electricity Act requires the group to take into account the conservation of natural features of beauty and other items of particular interest and lays down the terms under which environmental assessments and formal statements on the preservation of amenity are made.

The Utilities Act provided for environmental guidance to be given by the Secretary of State to Ofgem, and for regulations to be drawn up which require licensed electricity suppliers to secure a certain percentage of their supplies from renewable energy sources, compliance being demonstrated by tradable ROCs or payment of a “Buyout Price”. The current requirement is that 15.4% of UK energy should come from renewable sources by 2015/16. The Utilities Act also provided for residential energy efficiency targets to be set for licensed suppliers and to be implemented by the EEC.

The Environmental Protection Act of 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. The Contaminated Land Regulations, which implement provisions of the Environment Act 1995, require local authorities to identify sites where significant harm is being caused and to take appropriate steps. In order for harm to be demonstrated it must be shown that a source of pollution, a receptor and a pathway are present. Harm may be eliminated by clean-up or by breaking the source to receptor pathway. Clean-up is only required to “fit for subsequent use” standards, so that environmental compliance is consistent with the intended use of the site.

The EU ETS commenced on 1 January 2005 and works on a “cap and trade” basis where installations are allocated a number of allowances which they can then trade to achieve reduced CO2 emissions at least cost. ScottishPower has 13 installations covered by the scheme and has fully integrated CO2 management into its energy portfolio, managing CO2 as a commodity alongside power, gas and coal. EPA 1990 is the primary UK statute governing the environmental regulation of power stations. In April 1991, it introduced a system of Integrated Pollution Control (“IPC”) for large scale industrial processes, including power stations. The EU has agreed a Directive on Integrated Pollution Prevention and Control, which introduces a system of licensing for industrial processes such as

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power stations. This Directive is being implemented via the Pollution Prevention and Control Regulations which will bring modifications to the IPC regime into effect, on a staged basis, during 2006. ScottishPower has seven plants covered by these arrangements. The EU has adopted a framework directive on ambient air quality assessment and management and protocols regarding reductions in the emissions of SO2 and NOX have been agreed. Compliance with these requirements will continue to be implemented in the UK by means of the National Air Quality Strategy published in 1997, and reviewed in 2000.

NORTH AMERICAN ENVIRONMENTAL REGUL ATION

US and Canadian federal, state and local authorities regulate many PPM Energy activities pursuant to laws and regulations designed to prevent and control pollution and restore, protect and enhance the quality of the environment. These laws and regulations govern the construction, permitting, operation and closure of PPM Energy facilities. In general, these laws and regulations give rise to permit and pollution control requirements and other liabilities administered under numerous regulatory authorities, principally in respect of Clean Air Act matters, site clean-up, clean water regulations and protecting Wildlife pursuant to the Endangered Species Act and Migratory Bird Treaty Act.

9.2.7 SUPPLIERS

ENSURING RESPONSIBLE CONDUCT BY SUPPLIERS

In the group’s fuel purchasing activities, the reviews conducted before entering into contracts cover cost, quality and risk, credit worthiness, Financial Services Authority compliance, legal issues and social reviews, including environmental and social compliance, social and welfare arrangements of local employees and employee compensation.

In its non-primary fuel procurement activities, group processes include policies, pre-qualification and evaluation criteria and supplier audits focused on employee health and safety and general working conditions, as well as environmental practices and performance.

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 DTI 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 2006 for its UK businesses and US businesses were 5 days and 42 days, respectively.

Further details of group procurement policies, management and performance in the ‘Corporate Responsibility’ section of www.scottishpower.com.

9.3 RISK FACTORS

9.3.1 INTRODUCTION

There are risks and uncertainties inherent in the group’s business which could materially affect the group’s business, its revenue, operating profit, net assets, liquidity and capital resources. The group’s risk management processes are designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in the group’s business and activities; measure quantitative market risk exposure; and identify qualitative market risk exposure in its business.

9.3.2 RISKS RELATING TO THE GROUP’S BUSINESS

The UK Government’s energy policy could change, negatively affecting the context in which the group has established its UK business strategy.

In the UK, the Government published a White Paper in February 2003 setting out energy policy. The Government issued a second annual report on the implementation of the White Paper in July 2005, and recently launched an Energy Review that is broad in scope and considers all aspects of the energy system including both energy supply and demand. Whilst the outcome of the Energy Review and its impact on the group are unknown, these documents emphasise a continuing intention to make use of a balance of market-based and regulatory mechanisms to maintain the reliability and security of energy supply whilst seeking to reduce the use of carbon, boost energy-saving and maintain efforts to mitigate the impact of fuel costs on lower-income households. There is particular focus on the electricity and gas sectors with an emphasis on encouraging investment in new generation sources, renewable electricity, energy storage, transmission and distribution infrastructure. The Government’s policy objectives are evolving but appear to be largely consistent with EU policy generally. However, as the policy outlined extends well into the future, it could be subject to change and amendment by the present or future Governments. Equally, the European Commission (“the Commission”) has published a Green Paper reviewing EU energy policy, with concrete proposals due by the end of 2006. Changes at the UK or EU level could affect the group’s business, results of operations or financial condition.

Changes in regulatory requirements and/or modification of the group’s current licences could negatively affect the group’s business, results of operations or financial condition.

The Commission, the Council of the European Communities and the European Parliament have put in place a regulatory framework for the energy sector in the EU (including, insofar as applicable, the UK). Changes to the EU regulatory framework may therefore impact directly or indirectly on the group’s activities. For example, the Commission recently produced its ‘Report on progress in creating the internal gas and electricity market’ on 15 November 2005, which examines the extent to which markets have been liberalised in line with EU policy. As a result, the Commission has launched infringement procedures

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against 17 member states (including the UK) in relation to their alleged failure to implement EU liberalisation legislation. At the same time, the European Regulators’ Group for Electricity and Gas (the “ERGEG”) has launched the Electricity Regional Initiative (27 February 2006) and the Gas Regional Initiative (25 April 2006). ERGEG is an advisory body that assists the Commission in developing an EU internal market for energy. The initiatives aim to identify barriers to progress, and develop options for overcoming these barriers.

Within the UK, the electricity and gas industries are regulated primarily through powers assigned, under the Utilities Act to the Authority which licenses industry participants, enforces licence conditions, regulates quality of service and sets pricing formulae for electricity transmission and distribution activities. In principle, the Authority has wide discretion in the exercise of its obligation to act to protect the interests of customers, by promoting effective competition wherever appropriate. The Authority may propose modifications to licence conditions (licences contain standard licence conditions, which apply to all classes of licence, and special conditions particular to that licence), to which licence holders may agree or object. In the absence of agreement from the holder of a special licence condition, or if objections are above the specified minority threshold for a standard licence condition, the Authority may instead seek to secure a modification through a modification reference to the Competition Commission.

Ensuring that licence holders are able to finance their functions is one of a number of other factors which the Authority must consider. The Authority seeks to promote competition in certain markets (such as those in which Energy Retail and Energy Wholesale are active), and imposes limitations on the rates that may be charged in markets where the regulatory regime does not consider competition to be appropriate (such as those in which Energy Networks is active). The Authority published consultation documents in July 2005, December 2005 and March 2006 as part of its revision of price controls for gas and electricity transmission companies to apply from April 2007. Alterations to the price controls imposed on certain of the group’s activities, modifications to licence conditions or other regulatory changes in the UK or EU may negatively affect the group’s compliance costs, its business, results of operations or financial condition.

The volatility of commodity costs may have an adverse effect on the results of operations.

The costs incurred by Energy Wholesale are impacted by wholesale energy prices, including the price of carbon, coal, gas and electricity. Wholesale gas and electricity prices in the UK have increased by over 60% compared with the prior year and the price of these commodities remains volatile. The group has been able to mitigate this through a hedging programme over the short-term but has had to institute retail energy price rises. If these conditions sustain or worsen, the group may have to pass through further increased costs to consumers via its Energy Retail business, which could lead to customer losses, and/or changes in demand, which may have an adverse effect on the group’s business, results of operations or financial condition. Additionally, if wholesale energy prices remain high or continue to increase and the group is not able to pass such costs through to consumers or to hedge effectively against such rises, this may have an adverse effect on the results of operations.

In addition, short-term price spikes, where prices can increase by as much as 200%, have been observed where an unexpected cold snap coincides with supply problems such as the recent outage at the Rough gas storage facility. The UK is increasingly vulnerable to this kind of event as its own gas production declines and greater reliance is placed on imported gas. Lack of

liquidity in traded markets and poor access to transit pipelines throughout Europe add to the risk of an adverse effect on the results of operations.

The assets and business processes of the group may not perform as expected, which could impact the group’s business, results of operations or financial condition.

The group’s assets, mechanical and IT systems, as well as its business processes and procedures, might not perform as expected which may adversely affect operational, and potentially, business performance. The group relies on complex IT systems. Among other factors, mechanical and operational interruptions including as a result of technical and human factors and weather conditions can result in outages or damage to infrastructure or plant and damage or interruptions to these systems may adversely affect the group’s operations. This may affect the group’s business, results of operations or financial condition, unless the group resorts to unanticipated network repairs or an unanticipated market transaction to meet any generation shortfall, neither of which may be possible or which may only be possible on adverse terms, and may have an adverse effect on the group’s business, results of operations or financial condition.

Loss of market share and profit margins due to increased competitive pressures.

The group’s non-regulated businesses operate in competitive markets. A change in the level of marketing undertaken by market participants or in their pricing policies, irrational behaviour by market participants or consolidation between them could have a significant adverse effect on sales, revenues and results of operations.

Licences held by the group may be terminated or revoked.

The group is required by UK legislation to hold various licences in order to carry out its business activities in the UK. Such licences may be terminated in accordance with their notice provisions, or revoked in certain circumstances specified in the licence. These circumstances include the insolvency of the licensee, the licensee’s failure to comply with an enforcement

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order made by the Authority and the licensee’s failure to carry on the activities authorised by the licence. Revocation or termination of these licences would have a material adverse effect on the group’s business, results of operations or financial condition.

Measures that could be imposed under competition law by the Commission, the Authority, the OFT or the UK Competition Commission could negatively affect the group’s business, results of operations or financial condition.

The Commission, the Authority, the OFT and the UK Competition Commission all have powers to apply aspects of competition law in relation to the UK. These bodies may examine the conduct of individual companies, or carry out a broader investigation into markets more generally. Such investigations could result in the imposition of measures on individual companies or the industry in general to remedy or penalise behaviour (for example, by imposing significant fines, or structural or behavioural remedies) that is deemed to impede the successful functioning of the markets. If an infringement ruling is made, individual companies could also face civil damages actions from third parties. Such measures or civil actions could adversely affect the group’s revenue and profitability. The preliminary report of the Commission’s recent “Energy sector inquiry” (published on 16 February 2006) identified what it considered to be serious malfunctions of the energy markets in the EU. The Commission has stated that it will pursue further investigations targeted at specific companies, potentially leading to action being taken against them (including significant fines, or structural or behavioural remedies). This may affect the group.

Recently enacted energy legislation in the US could have unpredictable effects on the nature and extent of regulations to which the group is subject and on its revenues or profitability.

In the US, PPM Energy conducts business in conformance with a multitude of federal and state regulatory laws. During the past several years, the United States Congress has actively considered, and will continue to actively consider, significant changes in energy and environmental policy that may affect PPM Energy’s business. In August 2005, President Bush signed into law the Energy Policy Act of 2005 (“EPAct 2005”). Among other actions, EPAct 2005 repealed the Public Utility Holding Company Act of 1935, as amended and enacted the Public Utility Holding Company Act of 2005, effective 8 February 2006. EPAct 2005 encourages additional investment in renewable facilities by, among other things, extending authorisation of the ten-year renewable energy production tax credits to projects placed in service through the end of 2007. The sale of PacifiCorp will impact the group’s ability to fully utilise these tax credits on a timely basis. Financing structures exist to enable the group to redeem value from the tax credits. PPM Energy completed its first wind portfolio financing structure in May 2006 through which it will realise the value of associated wind tax benefits and expects to undertake similar transactions for substantial portions of its owned windfarm assets during 2006/07. However the continued availability of such structures cannot be guaranteed. Further extensions of such production tax credits and PPM Energy’s ability to use such credits may have a significant influence on PPM Energy’s future investment strategy and performance and could affect the group’s business, results of operations or financial condition.

Breaches of environmental or health and safety laws or regulations could expose the group to claims for financial compensation and adverse regulatory consequences and could damage the group’s reputation. Taken together with the inherent uncertainty surrounding the extent or timing of the general trend towards tightening regulation of environmental impact, the group may fail to meet predicted revenues or profitability.

Aspects of the group’s activities are inherently hazardous, such as the operation and maintenance of electricity lines and the storage of natural gas. Electricity and gas utilities also typically use and generate in their operations hazardous and potentially hazardous products and by-products. In addition, there may be other aspects of the group’s operations that are not currently regarded or proved to have adverse effects but could become so, for example the effects of electric and magnetic fields. The group is also subject to laws and regulations governing health and safety matters, protecting both the public and its employees.

The group is subject to laws and regulations relating to pollution, the protection of the environment and how the group uses and disposes of hazardous substances and waste materials. These laws and regulations require the group to obtain and maintain permits and approvals for the group’s operations and impose liabilities, including fines, penalties and other costs, in the event of regulatory and/or permit non-compliance.

In addition, environmental laws in the US impose liability including without regard to fault for releases of hazardous substances into the environment, and the group could be liable under these laws and regulations at current and former group facilities and third party sites where the group has sent wastes. Federal, state and local authorities regulate many of the group’s US activities pursuant to laws designed to restore, protect and enhance the quality of the environment.

The group cannot predict what impact, if any, future changes in environmental or health and safety laws and regulations including as a result of the general tightening of environmental regulation may have on the group’s results of operations or financial condition.

Any breach of these obligations, or even incidents relating to the environment or health and safety that do not amount to a breach, could adversely affect the group’s reputation or business, results of operations or financial condition.

The group’s businesses face a number of financial risks.

The group faces various financial risks. The principal financial risks faced by the group are wholesale energy prices (as referred to above and discussed further below), credit/counter-party risk,

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liquidity risk and long-term supply risk. In addition, increases or reductions in future retail demand for electricity as a result of economic growth or downturns, among other factors, including abnormal weather, may impact retail revenues, cash flows and investment levels.

Given the nature of the group’s operations, the group is exposed to various credit risks arising as a result of the contractual obligations of wholesale trading partners, suppliers and industrial and commercial customers. Whilst the group has put in place group-wide guidelines to mitigate against this risk, credit risk may adversely affect the group’s business, results of operations or financial condition.

Given the need for strong liquidity to operate effectively across the group, especially in the power and gas markets, the group is required to ensure that its debt maturities are spread over a wide range of dates and over a suitable range of financial products. The group’s ability to obtain suitable levels of liquidity depends on the group’s financial performance and general financial and economic conditions including credit rating. Failure to maintain access to financial liquidity may adversely affect the group’s business, results of operations or financial condition.

Energy Wholesale’s ability to balance its whole portfolio of assets and customers depends, to a large extent, on its ability to secure the long-term supply of electricity, gas and coal. In addition to its own generation activities, Energy Wholesale currently has in place a number of long-term supply contracts. It is uncertain on what terms additional or replacement supplies would be available to the group. Failure to secure alternative sources of supply and/or favourable terms on which such supply can be obtained may adversely affect the group’s business, results of operations or financial condition.

Failure to address rising customer debt in a market with rising retail prices and limited sanctions against customers may adversely affect the group’s business, results of operations or financial condition. In order to mitigate against this risk, the group employs proactive debt management.

In order to mitigate certain of the financial risks identified, the Board has endorsed the use of derivative financial instruments including swaps, both interest rate and cross-currency, swaptions, options, forward-rate agreements, financial and commodity forward contracts, commodity futures and commodity options. The continued availability of these products and the implementation of a successful hedging strategy cannot be assured and if either of these circumstances cease to continue, this could adversely affect the group’s business, results of operations or financial condition.

The effective rate of tax paid by the group may be influenced by a number of factors including changes in law and accounting standards and the group’s overall approach to such matters, the results of which could increase or decrease that rate. The group seeks to manage its financial structure efficiently to reduce the overall tax burden on the business where practicable. The continued ability of the group to manage its businesses in this way cannot be assured and failure to do so could affect operational, and potentially, business performance. HM Revenue

& Customs and the Internal Revenue Service are reviewing the tax aspects of certain financing arrangements with SPHI. The company believes that prudent provision has been made against potential tax liabilities which may arise as a result of the group’s financial structure however this cannot be guaranteed.

IFRS may result in increased volatility in the group’s reported results of operations or financial condition.

Notwithstanding the above arrangements, exposure to these risks (or other unidentified financial risks) could adversely impact the group’s business, results of operations or financial condition.

The group’s overall financial position may be adversely affected by a number of factors including restrictions in borrowing and debt arrangements and changes to credit ratings.

The group is subject to certain covenants and restrictions in relation to its listed debt securities and its bank lending facilities. The group is also subject to restrictions on financing that have been imposed by regulators. These restrictions may hinder the group in servicing the financial requirements of its current business or the financing of newly acquired or developing businesses. The debt issued by the group and certain of its subsidiaries is rated by credit rating agencies and changes to these ratings may affect both the borrowing capacity of the group as a whole and the cost of these borrowings. These factors could adversely affect the group’s business, results of operations or financial condition.

The group’s pension plan funding obligations are significant and are affected by factors beyond its direct control.

Estimates of the amount and timing of future funding obligations for the group’s pension plans are based on various assumptions including, among other things, the actual and projected market performance of the pension plan assets, future long-term corporate bond yields, improving longevity of members and statutory requirements. In the last year the relative improvement in equity markets has seen the plans’ asset value rise; however this has been offset by falling bond yields and, therefore, the liabilities have increased in value. The group has recently agreed terms with the trustees and the Pensions Regulator for accelerated repair plan proposals to reduce the amount of the deficits in respect of the group’s pension plans. For further information, please refer to Section 7.2 on page 26 of this document. In addition, while the group is consulted by the trustees on the investment strategies of its pension plans, the group has no direct control over these matters as the trustees of each plan are responsible for determining investment strategy. The position will continue to be monitored by the company and the trustees. Further deterioration in the plans’ asset values or increase in liabilities would be likely to increase the group’s funding obligations and could adversely affect the group’s business, results of operations or financial condition.

The group’s businesses may be vulnerable to acts of terrorism.

Terrorism threats are an ongoing risk to the entire utility

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industry, including ScottishPower. Potential disruptions to operations and information technologies or destruction of facilities from terrorism, including cyber attacks, are not readily determinable and could adversely affect the group’s reputation and its business, results of operations or financial condition.

Disposed businesses may expose the group to costs that could have an adverse effect on its results of operations, cash flow and financial condition.

The group has carried out a number of strategic disposals, in the course of which it has given to certain other parties to those transactions certain representations, warranties, covenants and indemnities in respect of them.

The extent to which ScottishPower will be required in the future to incur costs or liabilities in connection with warranty and/or indemnity claims or otherwise in connection with such disposals is not known and, if ScottishPower should incur any such costs, these costs could have an adverse effect on its business, results of operations or financial condition.

The group’s businesses face a number of litigation risks.

The group’s businesses are parties to various legal claims, actions and complaints (actions pending or threatened), certain of which may 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 Board currently believes that disposition of these matters will not have a materially adverse effect on the group’s results of operations or financial condition.

9.3.3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT

MARKET RISK

RISK CONTROL ENVIRONMENT

The group’s strategy is to conduct business in a manner benefiting customers through balancing cost and risk while delivering shareholder value and protecting the group’s performance and reputation by prudently managing the risks inherent in the business. To maintain this strategic direction the group develops and implements risk management policies and procedures, and promotes a rigid control environment at all levels of the organisation.

The risk policy developed by the Board is supported by a governance structure, which includes the ET, a Business Risk and Investment Committee (“BRIC”) for each business, Business Risk Assessment Teams and the independent Group Risk Management function.

The structure ensures that the risk management procedures established for each business to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in its business are adequately designed and implemented and that an effective and efficient system of internal controls is maintained. The businesses adhere to their specific business risk limits and guidelines which are endorsed by the BRIC and approved by the ET. These limits are consistent with the allocation of group risk capital to the businesses. The business limits are allocated based upon the group’s total risk capital, being the capital that would cover acceptable potential losses resulting from market and credit risks. The Board has allocated a certain amount of risk capital, based on a 99% confidence interval over a two-year period. This risk capital amount is calculated as the maximum sustainable loss over a two-year period such that the group’s financial ratios would still warrant an investment grade rating from rating agencies such as Standard & Poor’s or Moody’s.

The risks faced by the group fall in the following categories: market risk (both energy price and energy volumetric risk), operational risk, credit risk, weather risk, interest rate risk, inflation risk, insurance risk, foreign exchange risk, liquidity risk, derivative risk, administrative risk, legal risk, regulatory risk, political risk, security risk, pension risk and risks relating to the availability of generation, adequate fuel supply and transportation.

The Board’s position on risk and strategy for risk management are contained in the Group Energy Management and Risk Management Policy. The Board implements its policies through a rigid risk governance structure, whereby responsibilities are vested with groups, committees and individuals on a global as well as business level. Further details on the group’s risk policy are given in the individual risk sections below.

Generally, the risk management policy and control environment ensures that transactions undertaken and instruments used fall into the types of transactions approved by the Board and are properly validated within the authorised levels of authority. Transactions include instruments such as physically-settled instruments, financially-settled instruments, other contractual obligations, regulatory requirements, and other obligations. The types of instruments which can be used are approved for each business. Subject to the limits requirements discussed above, no transaction is executed unless it is an instrument approved by the BRIC. Further information on the value of derivative instruments utilised by the group is disclosed in Note 25 to the Accounts. Authorised personnel are permitted to engage only in those activities specified in the businesses’ operational policies and procedures.

A clear reporting structure has been implemented within the group. It ensures that the portfolios are monitored on a timely basis and sufficient information is made available to management to enable quick response of the business to the dynamic characteristics of its market environment. Those reports include daily position, mark-to-market (“MtM”) and Value at Risk (“VaR”) reports, as well as periodical fundamentals reports, stress and scenario reports, credit watch, credit exposure, accounting and insurance reports.

ENERGY RISK MANAGEMENT

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control and management framework is established and maintained to monitor and measure risks in existing portfolios of assets and contracts, to develop and define appropriate strategies and transactions to manage those risks and to approve and authorise new transactions and energy instruments. The policy is reviewed at least on an annual basis to ensure that its relevance to the current environment is maintained.

Each business of the group that engages in energy management activities establishes a set of operational policies and procedures incorporating the policies and principles set forth in the Group Energy Management and Risk Management Policy and provides detailed information with respect to the roles and responsibilities of each function involved in EMRM activities. These operational policies and procedures are presented to the BRIC for approval at least annually.

In order to manage the impact of financial risks to the group and report results consistent with the operational strategies, the Board has endorsed the use of derivative financial instruments as hedging tools. Those instruments include fixed and floating swaps (interest rate, cross currency and commodity agreements), swaptions, financial options, forward rate agreements, financial and commodity forward contracts, commodity futures, commodity options and other complex derivatives. Such physically- and financially-settled instruments are held by the group to match exposures and are not held for financial trading purposes. Exceptions exist in the group’s competitive businesses, PPM Energy and Energy Retail & Wholesale, where a limited and controlled number of transactions and derivatives may be held for proprietary trading purposes.

The group uses a number of risk measurement procedures and techniques to ensure that risk is kept within pre-approved limits. These include earnings volatility control (daily VaR calculation), MtM stop loss limits, price exposure by tenor limits, stress tests and scenario analysis as well as individual transaction and physical position limits. The latter are defined as a maximum commitment value of an individual transaction, physical size of a transaction, VaR impact of the transaction, tenor, instrument types and other relevant measures. Valuation is undertaken on a daily basis by portfolio and exposure is assessed within a two-year rolling forward horizon. All valuation models are reviewed and approved by Risk Management on an ongoing basis, including changes to assumptions and model inputs. Changes that can have significant impact on the Accounts require additional review and approval by the BRIC, ET or Board, as appropriate.

The group utilises hedging instruments in accordance with the approved risk strategies designed to keep exposure within the risk limits discussed above.

VaR is a measure of the potential financial loss on a price exposure position over a defined period to a given level of confidence. VaR computations for the group’s energy commodity portfolios are based on a historical simulation technique or a Monte Carlo simulation technique, which utilises historical or stochastically simulated energy market forward price curve changes to estimate the potential unfavourable impact of price changes in the portfolio positions scheduled to settle within the forward 24 months. The quantification of market risk using VaR provides a consistent measure of risk across the group’s continually changing portfolio. VaR is not necessarily indicative of actual results that may occur. Future changes in markets inconsistent with historical data or assumptions used could cause actual results to exceed predicted estimates. The group’s VaR computations for its energy commodity portfolio utilise several key assumptions, including a 99% confidence level for the resultant price changes and a holding period of five business days. Table 29 provides details of the businesses’ VaR measurements.

TABLE 29

VaR measurements (£m)

Average daily VaR Maximum VaR Minimum VaR

2005/06 2004/05 2005/06 2005/06

Energy Retail & Wholesale 11.1 8.0 17.6 6.0

PPM Energy 8.7 5.4 13.3 3.2

VaR, while sensitive to changes in portfolio volume, does not account for commodity volume risk. Commodity volume risk is defined as the possibility that a change in the supply of, or demand for, the commodity will create an unexpected imbalance and change the requirements for the commodity. ScottishPower applies stress tests to reinforce its VaR measurements and uses stochastic analysis to estimate the impact of risks on outcomes.

ENERGY PRICE AND VOLUME RISK MANAGEMENT

ENERGY RETAIL & WHOLESALE

On 1 April 2005, the introduction of BETTA combined the Scottish wholesale market with the wholesale market in England & Wales, creating a Great Britain-wide wholesale electricity market with suppliers, traders and generators trading firm physical forward contracts for bulk electricity supply.

Under BETTA, the balancing mechanism, which is operated from one hour ahead of real-time (gate closure) up to real-time by the National Grid Company, is now used to manage the entire Great Britain 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 output as a generator or demand as a customer. The mechanism also provides for calculation and settlement of imbalance charges and revenues arising from the differences between parties’ contract positions and their actual physical energy flows.

Energy Retail & Wholesale have procedures in place to minimise exposure to uncertain balancing mechanism prices, that is, the possibility of high charges arising from shortfalls in physical energy or low revenues from sales of surplus physical energy. The businesses enter into bilateral contracts for the sale and purchase of energy across a range of time periods to minimise exposure to the balancing mechanism and its portfolio of flexible generating assets can be used up to gate closure to minimise further this exposure and also to attract premium

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income from providing flexible electricity to the balancing mechanism. A proportion of the output from several of the group’s UK windfarms is dispatched directly as generated into the distribution system; however exposure to imbalance charges for this volume is largely mitigated through persistence modelling of the site output up until gate closure.

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

The businesses also have procedures in place to minimise exposure to natural gas price variations, which are managed in a similar manner to electricity price exposure, that is through a combination of longer-term contracts and shorter-term trading contracts with flexible delivery profiles, certain derivative financial instruments and through the use of flexibility within the portfolio of electricity generation and natural gas storage assets.

Exposure to coal price risk is mitigated through the use of a combination of financial and physical contracts as well as currency hedges executed by the ScottishPower treasury function.

Cover against volatile spot prices is built up on a rolling basis through the year and, at 31 March 2006, a significant proportion of the businesses’ exposure to electricity, natural gas and coal price variations for the period to 31 March 2008 had been mitigated. Following the commencement of the EU’s ETS in January 2005, exposure to carbon emission allowance price variations are managed through trading contracts with delivery within each individual year throughout Phase 1 (2005-2007) and Phase 2 (2008-2012) of the ETS. The euro exposure arising as a result of managing this carbon price exposure is mitigated with currency hedges executed by the ScottishPower treasury function. Decisions taken by the UK Government or the EU in relation to the total number of emission allowances to be allocated under Phase 2 (and subsequent phases) of the EU ETS, and the method of their allocation between market sectors and participants may affect the company’s carbon positions and exposures.

Energy Retail & Wholesale manages its ROCs position by means of generation from the businesses’ own qualifying plants, through long-term renewable power purchase agreements and through market purchases. The value of ROCs is driven by the buy-out price (set under the Renewables Obligation Order) and the recycle value, which may be affected by the market level of electricity demand and of qualifying generation; the rate of development and construction of new qualifying generation; and decisions made by the government regarding the qualification of different technologies to receive ROCs in future.

Energy Retail & Wholesale measures the market risk in its energy portfolio daily utilising the VaR approach (described above), scenario reporting as well as other measurements of net position, and monitors its portfolio exposure to market risk in comparison to established thresholds. Open positions are also measured at price risk in terms of volumes at each significant delivery location for each forward time period.

PPM ENERGY

PPM Energy’s strategy is to match the capacity and output of its assets and long-term sales obligations, with any imbalances being managed via wholesale energy purchases and sales activities.

PPM Energy’s wind asset position is balanced with long-term forward sales and some spot sales of both energy and renewable attributes. Associated with the wind energy production are Renewable Energy Certificates (“RECs”) that represent the environmental attributes of the renewable energy. Wind generation resources are subject to price variability for that portion of the output that is not committed to long-term fixed price contracts. Imbalances in the REC portfolio are subject to price changes in the REC market.

Substantially all of the business’s owned or controlled thermal capacity is committed to long-term contracts, with any imbalance being subject to generation resource availability and the relationship of fuel (natural gas) costs to electricity prices (or “spark spread”). Short-term and daily imbalances are managed through real-time markets. The principal risk associated with this activity is if counterparties fail to perform in accordance with contracts or generation assets fail to perform at reasonable levels.

The business’s owned and contracted natural gas storage facilities are subject to a process of prudent risk limits, established risk information systems and clear reporting, with a business model designed to minimise commodity risk. Gas storage activities are subject to the risks associated with the operations and marketing of the storage facilities and services.

PPM Energy may maintain, or create, open positions in response to (or in anticipation of) long-term origination or development transactions. This creates exposure to market price movements, subject to market risk limitations delegated by ScottishPower and oversight by the corporate risk management group embedded in PPM Energy. As such, the business will participate in the wholesale electricity and natural gas markets to manage its open positions. In addition, PPM Energy engages in point-of-view energy management activities in accordance with strict limits approved by the ET and BRIC. Control and performance metrics for such activities are tracked daily.

PPM Energy measures the market risk in its natural gas and electricity portfolio daily utilising the Monte Carlo VaR approach (described above), as well as other measurements of net position, and monitors its portfolio exposure to market risk in comparison to established thresholds. Open positions are also measured in terms of volumes at each delivery location for each forward time period.

CREDIT RISK MANAGEMENT

Credit risk is the financial exposure generated by the potential default of third parties in fulfilling their obligations. It is mitigated and monitored by setting approved credit risk limits at both the counterparty and portfolio level. At the counterparty level the group employs specific eligibility criteria in determining appropriate limits for each prospective counterparty and

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supplements this with netting and collateral agreements including margining, guarantees, letters of credit and cash deposits where appropriate. Counterparty exposures are then monitored on a daily basis.

The group also sets limits at the aggregate level to ensure the overall portfolio credit exposure remains within limit. Limits on counterparty concentration are placed and monitored at both the individual business level and also on the combined portfolio.

TREASURY RISK MANAGEMENT

The group treasury function is authorised to conduct the day-today treasury activities of the group within policies set out by the Board. The group treasury function reports regularly to the Board, through the monthly Group Performance and Risk Report and is subject to internal audit.

INTEREST RATE RISK MANAGEMENT

The group continues to manage its interest rate exposure by maintaining a percentage of its debt at fixed rates of interest. This is done either directly by means of fixed rate debt issues or by use of interest and cross-currency swaps to convert variable rate debt into fixed rate debt and fixed/variable non-functional currency denominated debt into fixed rate functional currency debt. The use of derivative financial instruments relates directly to underlying existing and anticipated indebtedness.

The exposure to fluctuating interest rates is managed by either issuing fixed or floating rate debt or using a range of financial derivative instruments to create the desired fixed/floating mix. The group’s interest rate policy is to target a long-term benchmark of at least 70% fixed rate interest. At 31 March 2006, 60% of gross debt was at fixed rates of interest (the comparison with net debt being distorted by the existence of large temporary cash balances). At March 2005, 98% of the net debt was either issued as fixed or converted to fixed rates using interest rate swaps. The weighted average period to maturity of year end fixed debt and interest swaps was eight years. Based on floating rate debt of £1,450 million at 31 March 2006, a 1% change in interest rates at that date would result in a £14.5 million change in profit before tax over a twelve-month period. Substantial floating rate cash balances held at 31 March 2006 for the return of cash and further investment in the businesses will reduce this effect.

All treasury transactions are undertaken to manage the risks arising from underlying activities and no speculative trading is undertaken. The counterparties to these instruments generally consist of financial institutions and other bodies rated at least AA- or Aa3 by one of S&P or Moody’s respectively. Although the group is potentially exposed to credit risk in the event of non-performance by counterparties, such credit risk is controlled through credit rating reviews of the counterparties and by limiting the total amount of exposure to any one party to levels agreed by the Board. The group does not believe that it is over exposed to any material concentration of credit risk.

INFL ATION RATE RISK MANAGEMENT

In recognition of the fact that a portion of UK revenues are linked to inflation, Scottish Power UK plc maintains part of its debt portfolio in index-linked liabilities. This is done either through issues of debt or through swapping fixed rate debt into index-linked. Index-linked liabilities total £275 million, which represents around 8% of the UK debt portfolio.

INSURANCE RISK MANAGEMENT

been a general increase in premiums due to the effects of hurricanes and other natural disasters. Business Interruption insurance has generally increased due to increased exposures arising from significantly higher commodity prices. Other classes of insurance have resulted in net reductions in premiums due to competition in the insurance market and a favourable loss history. The group has worked closely with its insurance advisors and insurers to maintain efficiencies and long-term stability in premium costs. The renewal of the group’s main insurance policies for 2006/07 has been completed with commercial insurers delivering a net premium reduction, albeit with the group taking on increased exposures for some classes. These increased exposures are not deemed to be significant.

FOREIGN EXCHANGE RISK MANAGEMENT

TRANSLATION RISK

The principal objective of the group’s currency risk management and hedging strategy is to seek to mitigate exposure to movements in foreign exchange rates for dollar-denominated net assets. This is done by hedging a substantial proportion of US net assets with dollar liabilities. The resulting stream of dollar interest acts as a partial hedge to the translation of US profits. The group has dollar debt (including the $700 million convertible bond) totalling $2,200 million. $1,150 million of this amount has been swapped to sterling leaving $1,050 million of liabilities to hedge the group’s US net assets. All foreign currency derivative contracts are subject to the same controls as interest rate derivatives referred to above.

Any foreign currency denominated debt will be subject to retranslation at period end closing rates. A ten cent strengthening of the 31 March 2006 closing US dollar exchange rate would give rise to a £37 million increase in reported net debt at 31 March 2006.

TRANSACTION RISK

Transaction exposure arises principally as a result of the import of coal, biomass and capital equipment as well as the trading of carbon allowances in the UK and gas in North America. Where exposure arises as a result of imports of capital or other goods denominated in foreign currencies the exposure is hedged as soon as it is committed.

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LIQUIDITY RISK MANAGEMENT

In recognition of the long life of the group’s assets and anticipated indebtedness, and to create financial efficiencies, 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 entered into borrowing agreements for periods out to 2039. The weighted average period to maturity of year end debt was eight years. The group had undrawn committed revolving credit facilities totalling £500 million as at 31 March 2006 which provide backstop liquidity should the need arise. Net cash and cash equivalents amount to £3,583 million.

DERIVATIVE RISK MANAGEMENT

The use of derivative financial instruments (other than those described for energy commodities above) relates directly to underlying existing and anticipated indebtedness, foreign subsidiary net assets and business transactions denominated in foreign currencies.

During the year, as a direct result of the disposal of PacifiCorp, $3,700 million of cross-currency swaps and $1,212 million of interest rate swaps were cancelled.

Credit risk on non-energy commodity derivative transactions is mitigated by a policy of only using counterparties with a credit rating of AA- or above. Exposure to derivative counterparties is monitored using measures, dependent on the type of transactions, that take into account potential market volatility.

10 Critical Accounting Policies

& Accounting Developments

10.1 CRITICAL ACCOUNTING POLICIES – IFRS

The group’s Accounts have been prepared in accordance with IFRS for the first time for the year ended 31 March 2006, with comparative figures for the prior year restated accordingly. The group’s material accounting policies under IFRS are set out in full on pages 70 to 81.

In preparing the Accounts in conformity with IFRS, the directors are required to make estimates and assumptions that impact on the reported amounts of revenues, expenses, assets and liabilities. Actual results may differ from these estimates. Certain of the group’s accounting policies have been identified as requiring critical accounting judgements or involving particularly complex or subjective decisions or assessments. These are discussed below and have been determined by the group’s senior management and approved by the Audit Committee and should be read in conjunction with the full statement of ‘Accounting Policies’.

10.1.1 IFRS – FINANCIAL INSTRUMENTS

The group accounts for its derivative financial instruments in accordance with IAS 39. IAS 39 requires all derivatives to be recorded as assets and liabilities in the balance sheet at their fair value, except for those which qualify for specific exemption under the standard such as commodity contracts which are for the purposes of the group’s own purchase, sale or usage requirements. For derivatives designated as effective cash flow hedges, the changes in fair value of the derivative assets and liabilities are initially recognised in the hedge reserve and then subsequently transferred to the income statement as the hedged item is recognised in the income statement. For derivatives designated as net investment hedges, the changes in fair value of the derivative assets and liabilities are recognised in the translation reserve. In all other cases,

changes in fair values of the derivative financial instruments are recognised in the income statement in the period in which they arise.

The group’s valuation strategies for derivative and other financial instruments utilise as far as possible quoted prices in an active trading market.

Futures, swaps, and forward agreements are valued against the appropriate market-based curves. Forward price curves are developed using market prices from independent sources for liquid commodities, markets and products and modelled for illiquid commodities/markets and products.

Single-variable options are valued against market price and volatility curves. Dual-variable options are valued against market price, volatility and correlation curves between two variables. Volatility curves are developed for open positions in both liquid and illiquid markets. They are developed from actively traded options (implied volatility), where markets exist, or using historical forward volatilities and other relevant market data. Correlation curves are developed using historical spot and forward correlations and other relevant market data.

Structured transactions are disaggregated into their traded core components, and each component is valued against the appropriate market-based curves. For transactions where a market price for the point of delivery is not actively quoted, if possible, the transaction is valued at the most appropriate point of delivery where a market price exists with appropriate adjustments for the actual point of delivery, including if applicable currency adjustments.

Assets owned (long position) are valued against the quoted bid price. If assets are owed (short position) they are marked to the quoted offer price. Where valuation incorporates mid-market price data, additional liquidity adjustments are made to the fair value to bring it in accordance with the profile of net long/short exposure. The value of net long volatility positions is marked against the bid volatility curve. For net short volatility positions, the offer volatility curve is used. Other adjustments include discounting and credit adjustments, where those have not already been captured in the mark-to-market process.

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standard products. All models are subject to rigorous testing prior to being approved for valuation and subsequent continuous testing and approval procedures designed to ensure the validity and accuracy of the model assumptions and inputs.

The assumptions within the models used to value financial instruments are critical, since any changes in assumptions could have a significant impact on the fair values and movements which are reflected in the Group Income Statement and Balance Sheet. There is little formal guidance to assist in applying IAS 39 to non-treasury contracts. As a result, significant judgements must be made in applying IAS 39 to the group’s energy contracts in particular. Disclosures relating to the group’s derivative financial instruments are set out in Note 25 to the Accounts.

10.1.2 IFRS – REVENUE

In the UK, prices for electricity and gas supplied to retail customers are determined within competitive markets. The assessment of energy sales to customers is based on meter readings, which are carried out on a systematic basis throughout the year. At the end of each accounting period, amounts of energy delivered to customers since the last billing date are estimated and the corresponding unbilled revenue is estimated and recorded as sales. Unbilled revenues included within accrued income in the group’s balance sheet relating to the group’s retail customers of continuing operations at 31 March 2006 amounted to £297 million (2005: £246 million).

10.1.3 IFRS – TAX

The group’s tax charge is based on the profit for the year and tax rates in force at the balance sheet date. Estimation of the tax charge requires an assessment to be made of the potential tax treatment of certain items which will only be resolved once finally agreed with the relevant tax authorities. In particular, the tax returns of the group’s US businesses are examined by the Internal Revenue Service and state agencies on a several year lag. Assessment of the likely outcome of the examinations is based upon historical experience and the current status of examination issues. In addition, HM Revenue & Customs in the UK and the Internal Revenue Service in the US are reviewing the tax aspects of certain financial arrangements with ScottishPower Holdings Inc. (formerly PacifiCorp Holdings Inc.). The group believes that appropriate provision has been made against potential tax liabilities which may arise as a result of this review, however this cannot be guaranteed.

10.1.4 IFRS – IMPAIRMENT OF PROPERTY, PLANT AND EQUIPMENT

In certain circumstances, accounting standards require property, plant and equipment to be reviewed for impairment. When a review for impairment is conducted, the recoverable amount is assessed by reference to the net present value of the expected future cash flows of the relevant Cash Generating Unit (“CGU”), or disposal value if higher. The discount rate applied is based on the group’s weighted average cost of capital with appropriate adjustments for the risks associated with the CGU. Estimates of cash flows involve a significant degree of judgement and are consistent with management’s plans and forecasts.

10.1.5 IFRS – PROVISIONS AND CONTINGENCIES

In accounting for contingencies, the group applies IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’. IAS 37 requires that a provision be recognised where there is a present obligation as a result of a past event, it is probable that a transfer of economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. If these conditions are not met, no provision should be recognised.

Contingent liabilities are required to be disclosed in the Notes to the Group Accounts, unless the possibility of a transfer of economic benefits is remote. Contingent gains are not recognised

unless realisation of the profit is virtually certain. Appropriate disclosures of contingent liabilities are made regarding litigation, tax matters, and environmental issues, among others. The evaluation of these contingencies is performed by various specialists inside and outside of the group. Accounting for contingencies requires significant judgement by management regarding the estimated probabilities and ranges of exposure to potential loss. The directors’ assessment of the group’s exposure to contingencies could change as new developments occur or more information becomes available. The outcome of the contingencies could vary significantly and could materially impact the group’s results and financial position. The directors have used their best judgement in applying IAS 37 to these matters.

10.1.6 IFRS – RETIREMENT BENEFIT OBLIGATIONS

The group operates a number of defined benefit schemes for its employees which are accounted for in accordance with IAS 19 ‘Employee Benefits’ using the immediate recognition approach.

The expense and balance sheet items relating to the group’s accounting for pension schemes under IAS 19 are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, earnings increases, mortality and increases in pensions in payment. These actuarial assumptions are reviewed annually in line with the requirements of IAS 19. The assumptions adopted are based on prior experience, market conditions and the advice of plan actuaries.

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charge both increase as the discount rate is reduced. If the IAS 19 charge for the year ended 31 March 2006 and the pension liability at 31 March 2006 had been based on a discount rate 0.5% p.a. higher or lower than those actually used, the charge would have reduced or increased, respectively, by £7 million and the pension liability would have reduced or increased, respectively, by £240 million in respect of the group’s principal continuing pension schemes.

10.2 CRITICAL ACCOUNTING POLICIES – US GAAP

In addition to preparing the group’s Accounts in accordance with IFRS, the directors are also required to prepare a reconciliation of the group’s profit or loss and shareholders’ equity between IFRS and US GAAP. The adjustments required to reconcile the group’s profit or loss and shareholders’ equity from IFRS to US GAAP are explained in Note 44 to the Accounts. Certain of the group’s US GAAP accounting policies have been identified as requiring critical accounting judgements or involving particularly complex or subjective decisions or assessments and these are discussed below. The discussion below should be read in conjunction with the full discussion of the differences between the group’s IFRS and US GAAP accounting policies set out in Note 44 to the Accounts.

10.2.1 US GAAP – DERIVATIVE FINANCIAL INSTRUMENTS

US GAAP requires all derivative financial instruments within the scope of FAS 133 ‘Accounting for Derivative Instruments and Hedging Activities’ and certain other subsequent amending standards and guidance to be fair valued. Although there are differences of detail between US GAAP and IFRS with respect to accounting for derivative financial instruments for which no ready market exists, the assumptions used to value these instruments are equally critical under both US GAAP and IFRS.

10.2.2 US GAAP – IMPAIRMENT OF GOODWILL

FAS 142 ‘Goodwill and Other Intangible Assets’ deals with the accounting for goodwill and other intangible assets upon their acquisition and their subsequent measurement. The standard requires that goodwill is not amortised but is tested for impairment at least annually. Under FAS 142, the impairment test is in two stages. The first step is a screen for potential impairment. This compares an estimate of the fair value of the reporting unit that contains the goodwill with the carrying value of the net assets (including goodwill) in the balance sheet of that reporting unit. If this identifies a potential impairment then the second step is required. This requires assigning fair values to the assets and liabilities of the reporting unit (similar to what would be required under acquisition accounting). The difference between the fair value of these net assets and the estimate of the fair value of the reporting unit as a whole provides an implied fair value of the goodwill. If this implied fair value is less than the carrying value of the goodwill, then goodwill is impaired and an impairment charge requires to be recognised. In accordance with the requirements of the standard, the group performed its annual review at 30 September 2005. No impairment was identified as a result of this review.

10.2.3 US GAAP – RETIREMENT BENEFIT OBLIGATIONS

schemes was 5.4%. The discount rate used to calculate the minimum pension liability at 31 March 2006 was 5.0%. If a discount rate had been used for accumulated benefit obligation purposes which was 0.5% p.a. higher or lower than that actually used, the impact would have been to reduce or increase, respectively, the minimum pension liability by £56 million in respect of the group’s principal continuing pension schemes.

10.3 ACCOUNTING DEVELOPMENTS

10.3.1 IFRS DEVELOPMENTS APPLICABLE FOR THE YEAR

ENDED MARCH 2006

The group has prepared its Accounts in accordance with IFRS for the first time in the year ended 31 March 2006, with comparative figures for the prior year restated accordingly. The effects of the transition from UK GAAP to IFRS on the group’s previously reported Income Statement and Balance Sheets are set out in detail in Note 42 to the Accounts. In addition, the group has implemented IAS 32 and IAS 39 prospectively from 1 April 2005. The effect of the implementation of IAS 32 and IAS 39 on the Group Balance Sheet at 1 April 2005 is analysed in detail in Note 43 to the Accounts.

10.3.2 IFRS DEVELOPMENTS APPLICABLE IN THE FUTURE

In preparing these Accounts, the group has applied all relevant IAS, IFRS and Interpretations issued by the IFRIC which have been adopted by the EU as of the date of approval of these Accounts. The group does not expect that the adoption, in the future, by the EU of other IAS, IFRS and Interpretations of the IFRIC issued by the IASB but not yet approved by the EU will have a material effect on the group’s results and financial position. Assuming IFRS 7 ‘Financial Instruments: Disclosures’ is approved by the EU, this standard will be mandatory for the group for the year ending 31 March 2008. This standard would require the group to disclose additional information about its financial instruments, their significance and the nature and extent of the risks to which they give rise, together with greater details as to the fair value of its financial instruments and its risk exposure. There will be no effect on the group’s income or net

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assets of any future implementation of this standard.

10.3.3 US GAAP DEVELOPMENTS APPLICABLE FOR THE YEAR

ENDED 31 MARCH 2006

In June 2005, the Emerging Issues Task Force (“EITF”) reached consensus on Issue 05-6, ‘Determining the Amortisation Period for the Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination’. EITF 05-6 requires leasehold improvements acquired in a business combination to be amortised over the shorter of the useful life of the assets or a term that includes required lease periods and renewals deemed to be reasonably assured at the date of acquisition. Additionally, the Issue requires improvements placed in service significantly after and not contemplated at or near the beginning of the lease term to be amortised over the useful life of the assets or a term that includes required lease periods and renewals deemed to be reasonably assured at the date the leasehold improvements are purchased.

EITF 05-6 is effective immediately. The adoption of EITF 05-6 has not had a material impact on the group’s results of operations or financial position under US GAAP.

In December 2004, the FASB issued FAS 123 (revised 2004), ‘Share Based Payment’. FAS 123R replaces FAS 123 and supersedes APB 25. FAS 123R requires that the cost resulting from all share based payment transactions be recognised in the financial statements at fair value and that excess tax benefits be reported as a financing cash inflow rather than as a reduction of taxes paid. FAS 123R is effective for the group from 1 April 2006. From the effective date, compensation cost is recognised based on the requirements of FAS 123R for all new share based awards and based on the requirements of FAS 123 for all awards granted prior to the effective date of FAS 123R that remain unvested on the effective date.

During 2005 the FASB issued FASB Staff Position (“FSP”) 123R – 1, FSP 123R – 2 and FSP 123R – 3. These FSPs detail various aspects of the implementation of FAS 123R.

ScottishPower is in the process of assessing the impact of the adoption of FAS 123R on the group’s results of operations or financial position under US GAAP.

10.3.4 US GAAP DEVELOPMENTS APPLICABLE IN THE FUTURE

In November 2004, the FASB issued FAS 151, ‘Inventory Costs – an amendment of ARB No. 43, Chapter 4’. FAS 151 clarifies that abnormal amounts of idle facility expense, freight, handling costs and wasted materials (spoilage) should be recognised as current period charges and requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. FAS 151 is effective for fiscal years beginning after 15 June 2005.

In December 2004, the FASB issued FAS 153, ‘Exchanges of Non-monetary Assets – an amendment of APB Opinion 29’, which amends APB Opinion 29, ‘Accounting for Non-monetary Transactions’ to eliminate the exception for non-monetary exchanges of similar productive assets and replaces it with the general exception for exchanges of non-monetary assets that do not have commercial substance. FAS 153 is effective for non-monetary asset exchanges occurring in fiscal years beginning after 15 June 2005.

In March 2005, the FASB FSP FIN 47, ‘Accounting for Conditional Asset Retirement Obligations – an interpretation of FASB Statement No. 143’ which clarifies the application of FAS 143 ‘Accounting for Obligations Associated with the Retirement of Long-Lived Assets’ in respect of conditional asset retirement obligations. The FSP is effective in the first period beginning after 15 December 2005.

In November 2005, the FASB issued FSP FAS 115-1 and FAS 124-1, ‘The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments’. FSP FAS 115-1 and FAS 124-1 address the determination as to when an impairment in equity securities (including cost method investments) and debt securities that can contractually be prepaid or otherwise settled in such a way that the investor would not recover substantially all of its cost should be deemed other-than-temporary. FSP FAS 115-1 and FAS 124-1 nullifies certain requirements under EITF Issue No. 03-01 ‘The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments’ that required the investor to make an evidence-based judgement as to whether it has the ability and intent to hold an investment for a reasonable period of time sufficient for a forecasted recovery of fair value up to (or beyond) the cost of the investment in determining whether the impairment was other than temporary, and the measurement of the impairment loss. The guidance in FSP FAS 115-1 and FAS 124-1 is effective for reporting periods beginning after 15 December 2005.

In November 2005, the FASB issued FSP FIN 45-3 to provide clarification with respect to the application of FIN 45, ‘Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others’. FSP FIN 45-3 includes within its scope and provides guidance concerning the application of FIN 45 to a guarantee granted to a business (or to its owners) that the entity’s revenue (or the revenue of a specified portion of the entity) will meet a minimum amount (referred to as a minimum revenue guarantee).

The group does not expect the adoption of the above pronouncements to have a material impact on its results of operations or financial position under US GAAP.

In May 2005, the FASB issued FAS 154, ‘Accounting Changes and Error Corrections’. FAS 154 replaces APB Opinion No. 20, ‘Accounting Changes’ and FASB Statement No. 3, ‘Reporting Accounting Changes in Interim Financial Statements’. FAS 154 applies to all voluntary changes in accounting principle and changes the accounting for and reporting of a change in accounting principle, and requires the retrospective application to prior periods’ financial statements of a voluntary change in accounting principle unless it is impracticable. FAS 154 is effective for accounting changes and

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Business Review correction of errors made in fiscal years beginning after 15 December 2005. The adoption of FAS 154 will only have an effect when the group makes a change in accounting principle that is addressed by the standard.

Cautionary Statement

11 Regarding Non-GAAP Financial Information

ScottishPower management believes that the non-GAAP measures used by ScottishPower in the periods presented, when used in conjunction with other measures that are computed in accordance with IFRS, provide useful information to both management and investors and enhance an understanding of ScottishPower’s reported results.

The non-GAAP performance measures included in this Annual Report & Accounts represent the results of operations adjusted: (i) to exclude the effects of fair value gains and losses on operating derivatives and financing derivatives, excluding, for 2004/05 only, the impact on results of contracts which were previously marked to market or otherwise fair valued but are now subject to IAS 39. All of the group’s treasury activities and all but an immaterial proportion of the group’s energy management activities are undertaken with a view to economically hedging the group’s physical and financial exposures. A number of these contracts do not qualify for own use or hedge accounting under IAS 39 and are therefore fair valued through the Group Income Statement.

In addition, those contracts which do qualify for cash flow hedge accounting can have an element of hedge ineffectiveness, which is recorded in the Group Income Statement. ScottishPower management consider that this accounting treatment of fair valuing economic hedges and the resulting Group Income Statement volatility does not appropriately reflect the business purpose of these contracts. In order to provide a more meaningful presentation, the fair value movements on these contracts have been separated from all other aspects of the impact of IAS 39, which remains within underlying business performance.

(ii) to exclude exceptional items. These are items included in operating profit but classified as exceptional as ScottishPower management considers that by virtue of their nature, size or incidence, it is necessary for them to be displayed as a separate line item or separately within a line item if the financial statements are to be properly understood.

(iii) in relation to discontinued operations only, to exclude the reversal of the depreciation charge for PacifiCorp for the period from 24 May 2005 to 20 March 2006, which under IFRS was not recognised in the group’s results.

(iv) to exclude the taxation effect on the above items (i) to (iii).

ScottishPower management assesses business performance by adjusting IFRS statutory results to exclude the items described above. It does this to: ensure year-on-year comparability of results; adjust for non-recurring items and accounting entries in order to provide a more meaningful measure of underlying performance in the year; assist UK analysts and the business community in general, who regularly exclude the effect of applying IAS 39 and exceptional items when assessing and forecasting the results of UK companies.

As ScottishPower management considers that the IAS 39 accounting treatment for contracts, which do not qualify for own use or hedge accounting (as described above), does not appropriately reflect the business purpose of these contracts and that the exceptional items are material and non-recurring in nature. It also excludes these items from the primary financial indicators it uses for internal management reporting, forecasting, budgeting and planning purposes. In addition, the non-GAAP performance measures included herein are consistent with

measures used to determine group dividend policy and to reward and incentivise senior management. With respect to discontinued operations only, depreciation and amortisation of non-current assets held for sale prior to 21 March 2006, which under IFRS was not recognised in the group from 24 May 2005, have been included to ensure year-on-year comparability of results.

Presenting ScottishPower’s results both including and excluding these items, ensures investors are in a position to make fair and equitable comparisons between the financial results of our business and other companies. Nonetheless, ScottishPower recognises that presenting performance measures which exclude these items is additional disclosure to that required under IFRS. Furthermore, ScottishPower recognises that such non-GAAP performance measures should not be viewed as replacements for, or alternatives to, comparable IFRS measures; rather they should be considered as supplementary measures of ScottishPower’s operating performance. In addition, the non-GAAP measures used by ScottishPower may differ from, and not be comparable to, similarly-titled measures used by other companies.

As equal prominence is given to performance measures including and excluding these adjustments within the discussion included in this Annual Report & Accounts, ScottishPower management does not consider the inclusion of non-GAAP measures specifically relating to these items, to disadvantage or materially constrain a reader’s ability to assess ScottishPower’s performance.

ScottishPower management assesses the performance of its business by adjusting for these items, enabling management to focus on the operational performance of the business. Therefore, to provide more meaningful information, ScottishPower has focused its discussion of business performance on the results giving effect to these adjustments.

In the particular circumstances of the current financial year and the previous financial years, the charge recognised for exceptional items is significantly different and, therefore, make a year-on-year comparison of financial performance extremely difficult. The exceptional item for 2004/05 is non-recurring as

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no impairment of goodwill has occurred in the last two years and there is no expectation of a further exceptional impairment charge for goodwill in the next two years. The exceptional items for 2005/06 assets are all material items which would not normally occur as part of the group’s operations and which are not expected to occur in the next two years. They comprise: (i) an exceptional gain relating to the sale of the group’s underground natural gas storage project at Byley to E.ON UK plc; (ii) an exceptional charge relating to costs of the corporate restructuring announced on 6 September 2005; (iii) an exceptional charge relating to the impairment of the group’s aircraft leases; and (iv) an exceptional charge relating to probable liabilities in relation to a credit support facility.

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Board of Directors and Executive Team

Chairman

CHARLES MILLER SMITH (66) joined the Board as Deputy Chairman in August 1999 and was appointed Chairman in April 2000. Following a career with Unilever for some 30 years, during the last five of which he was Director of Finance and latterly of the Food Executive, he was appointed Chief Executive of ICI in 1995 and then served as Chairman from 1999 to 2001. He is a member of the board of the Indian company, ICICI One Source plc, and of the Ministry of Defence Management Board.

Chairman of the Economics Committee of the Confederation of British Industry and a Companion of the Institute of Management. He is also a Senior Advisor to Warburg Pincus International, LLC.

Non-Executive Directors

VICKY BAILEY (54) joined the Board in June 2004. Based in Washington DC, she is a former Assistant Secretary for Policy and International Affairs at the US Department of Energy and ex-member of the Federal Energy Regulatory Commission (“FERC”). She has also served as an Indiana state regulator, and was President of PSI Energy, Inc., Indiana’s largest electricity supplier, from June 2000 to July 2001. She was appointed to the board of Battelle, a global research and development organisation, in August 2005; and is currently President of her own public and legislative affairs consultancy, Anderson Stratton International, LLC. She will retire from the Board after the AGM in 2006.

EUAN BAIRD (68) joined the Board in January 2001. He served as Chairman and Chief Executive Officer of Schlumberger Limited from 1986 to 2003, and non-executive Chairman of Rolls-Royce plc until June 2004. He is a trustee of Tocqueville Alexis Trust and Carnegie Institution of Washington, and a member of the Advisory Committee of Banque de France. His current term of office will expire at the AGM in 2007.

DONALD BRYDON (60) joined the Board in May 2003 and is the senior independent director. He had an executive career in investment management and investment banking with the Barclays and AXA groups for 36 years. He is Chairman of Smiths Group plc, Taylor Nelson Sofres plc, and the London Metal Exchange. He is Chairman of the Code Committee of the Panel on Takeovers and Mergers. Following his re-appointment for a further three-year term, his current term of office will expire at the AGM in 2009.

NOLAN KARRAS (61) joined the Board in November 1999. He is President of The Karras Company, Inc., and a Registered Principal for Raymond James Financial Services. He is Chief Executive Officer of Western Hay Company, Inc., and a non-executive director of Beneficial Life Insurance Company. He continues as a non-executive director of PacifiCorp. He is Chairman of the Utah State Higher Education Board of Regents and a member of the board of Ogden-Weber Applied Technology College. He also served as a member of the Utah House of Representatives from 1981 to 1990, and as Speaker of the Utah House of Representatives from 1989 to 1990. He will retire from the Board after the AGM in 2006.

NICK ROSE (48) joined the Board in February 2003; he is Chairman of the Audit Committee and is the Committee’s designated “financial expert”. He is Chief Financial Officer of Diageo plc, having been appointed to this position in July 1999. Previously he held senior finance positions with GrandMet and was latterly Finance Director of International Distillers & Vintners

in 1996 and then of United Distillers & Vintners in 1997. He is also a director of Moët Hennessy. Following his reappointment for a further three-year term, his current term of office, subject to his re-election in 2006, will expire at the AGM in 2009.

NANCY WILGENBUSCH (58) joined the Board in June 2004. She is a distinguished community administrator and President of Marylhurst University in Portland, Oregon. She is a former chair of the Portland Branch of the San Francisco Federal Reserve, and a director of West Coast Bank. She was also formerly a non-executive director of PacifiCorp. Her current term of office will expire at the AGM in 2007.

Executive Directors

PHILIP BOWMAN (53) is Chief Executive, having been appointed to this position on 16 January 2006. He is the senior independent director of Burberry Group plc and a non-executive director of Scottish & Newcastle plc. Prior to joining Scottish Power plc, he was Chief Executive of Allied Domecq from 1999 to 2005. His career includes five years as a director of Bass plc (now Mitchells & Butler plc and Intercontinental Hotel Group plc) where he held the roles of Chief Financial Officer and subsequently Chief Executive of Bass Taverns. In addition he has been a director of British Sky Broadcasting Group plc, Chairman of Liberty plc and Chairman of Coral Eurobet plc.

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SIMON LOWTH (44) is Finance Director, having been appointed to this position in May 2006. In this capacity, he is responsible for the group’s financial performance and reporting, the development and delivery of the group’s financing strategy, risk management and key institutional and shareholder relationships. Since joining ScottishPower in September 2003 he has held the positions of Director, Corporate Strategy and subsequently Executive Director, Finance and Strategy. He was formerly a Director with McKinsey and Company, leading its UK industrial practice, serving clients in the energy and utilities, manufacturing and transport sectors. He holds an MA in Engineering from Cambridge University and an MBA from London Business School.

Executive Team

The Executive Team is constituted as a committee of the Board and includes not only the Executive Directors of the Board but also the following key Executives and Officers from the group. For US reporting purposes the members of the Executive Team are regarded as officers of the company.

JOHN CAMPBELL (40) is Director, Energy Wholesale, having been appointed to this position in September 2005. He joined ScottishPower as a Graduate Trainee in 1988 in the Operational Research Department. He was previously Managing Director of Energy Management for four years. His other past appointments have included Trading and Metering Director and Commercial Director for Customer Sales and Services. He is a graduate of the University of Strathclyde with a joint honours degree in Operational Research and Economics.

KEITH COCHRANE (41) was appointed Group Director of Finance in May 2005, and joined the Executive Team in October 2005. He is responsible for the Financial Reporting, Performance Management and Control, Tax and Treasury functions, and for developing and delivering the group’s integrated financing strategy. He joined ScottishPower in June 2003 and is a former Chief Executive and Finance Director of Stagecoach. He is a Chartered Accountant and has a First Class Honours degree in Accountancy from the University of Glasgow. He will leave the company in June 2006.

SHEELAGH DUFFIELD (39) was appointed Company Secretary in May 2006. Her responsibilities include the provision of all board and executive team services and the maintenance of the governance framework within the group, as well as shareholder services and compliance. Since joining ScottishPower in 1996 as Deputy Secretary she has served in various corporate strategy and legal roles. A qualified lawyer she was formerly Company Secretary and Head of Legal at Scottish Television (now SMG plc).

STEPHEN DUNN (46) was appointed Director, Human Resources and Communications in September 2005 and is responsible for Human Resources and Communications across the company. He has been with ScottishPower for over 25 years, working within both line and corporate human resources functions in various parts of the business. Since privatisation he has held a number of corporate roles and has been involved in all the group’s acquisitions and disposals. He is a board member of ScottishPower Learning, a council member of the CBI Scotland and a trustee of the ScottishPower and Manweb Pension Schemes. He was until recently a director of Hibernian Football Club, a professional soccer club in the Premier League in Scotland.

TERRY HUDGENS (51) was appointed Chief Executive Officer of ScottishPower’s competitive US energy business, PPM Energy, in May 2001 and joined the Executive Team in December 2001. He joined PacifiCorp as Senior Vice President of Power Supply in April 2000, having

previously spent 25 years with Texaco, Inc. He was formerly President of Texaco Natural Gas and served as Texaco’s senior representative and elected officer in the Natural Gas Supply Association. He is a member of the Board of Trustees of The Nature Conservancy in Oregon. He has a bachelor’s degree in civil engineering from the University of Houston.

WILLIE MACDIARMID (45) is Director, Energy Retail, having been appointed to this position in September 2005. He joined ScottishPower in 1989. His previous roles have included Managing Director of Customer Sales and Services, Sales and Marketing Director of Energy Supply (where he led ScottishPower’s strategy to maximise customer growth in the deregulating energy market) and Managing Director of ScottishPower’s former chain of electrical retail shops and superstores.

SUSAN REILLY (45) is Commercial Director, having been appointed to this position in May 2006. She has responsibility for group strategy and various business support functions, including Information Technology. She was previously Executive Vice President, PacifiCorp Holdings, Inc. where she had responsibility for the successful conclusion of the sale of PacifiCorp to MidAmerican Energy Holdings Company. Before that, as Managing Director, Strategic Transactions, she led the development of ScottishPower’s UK windfarm portfolio and the acquisition of the combined cycle gas turbine fleet. She joined the Executive Team in October 2005. Prior to joining ScottishPower in 1995, she qualified as an accountant with PricewaterhouseCoopers and spent ten years with various organisations in M&A activity.

DAVID RUTHERFORD (42) is Director, Energy Networks, having been appointed to this position in September 2005. He joined ScottishPower in 1985. He was previously Managing Director of SP PowerSystems. He holds a BSc in Electrical and Electronic Engineering from the University of Strathclyde and an MBA from Heriot Watt University.

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Board of Directors and Executive Team

MEMBERS OF THE NOMINATION COMMITTEE

Charles Miller Smith, Chairman Donald Brydon Nolan Karras Philip Bowman Nancy Wilgenbusch

MEMBERS OF THE REMUNERATION COMMITTEE

Nolan Karras, Chairman Euan Baird Donald Brydon Nick Rose Nancy Wilgenbusch

MEMBERS OF THE AUDIT COMMITTEE

Nick Rose, Chairman Vicky Bailey Donald Brydon Nolan Karras

BOARD AND EXECUTIVE TEAM CHANGES

Philip Carroll retired from the Board following the conclusion of last year’s AGM on 22 July 2005. Charles Berry and David Nish retired from the Board on 6 September 2005. Dominic Fry and Michael Pittman retired from the Executive Team on 6 September 2005. Ian Russell retired from the Board on 16 February 2006. Judi Johansen retired from the Board following the sale of PacifiCorp on 21 March 2006. Ronnie Mercer and James Stanley retired from the Executive Team on 31 March 2006 and 3 May 2006 respectively.

John Campbell, Stephen Dunn, Willie MacDiarmid and David Rutherford were appointed to the Executive Team on 5 September 2005. Keith Cochrane and Susan Reilly were appointed to the Executive Team on 21 October 2005. Philip Bowman was appointed to the Board on 16 January 2006. Sheelagh Duffield was appointed to the Executive Team on 1 May 2006.

In accordance with the Articles of Association, Philip Bowman will retire from office at the AGM and, being eligible, offer himself for election. In addition, Charles Miller Smith, Vicky Bailey and Nick Rose will retire by rotation at the AGM. Charles Miller Smith and Nick Rose, being eligible, offer themselves for re-election. Vicky Bailey will retire from the Board and accordingly does not seek re-election. Nolan Karras will also retire from the Board at the AGM. Details of Philip Bowman’s service contract are set out in the ‘Remuneration Report of the Directors’. Charles Miller Smith and Nick Rose do not have service contracts with the company.

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Corporate Governance

Corporate Governance Statement 6 Internal Control and Risk Management

Board Composition 7 Communication with Shareholders

Board Effectiveness 8 NYSE Corporate Governance Rules

Board Proceedings

Reports from Committees

Corporate Governance Statement

The Board is committed to good corporate governance. The purpose of this statement is to explain how the company has applied the principles contained in the UK Combined Code. It should be read in conjunction with the ‘Remuneration Report of the Directors’ on pages 57 to 68.

During the year ended 31 March 2006, the company complied with the provisions set out in the Combined Code, with the following two exceptions: B.1.4 – the value of any fees received by executive directors in respect of external non-executive appointments is not disclosed in the Remuneration Report as this is not considered relevant to ScottishPower; and D.1.1 – this provision is concerned with dialogue with major shareholders on issues of governance and strategy and an explanation of the company’s position in this respect is contained in the statement below under the heading Communication with Shareholders.

This statement also contains details of the company’s compliance with the applicable provisions of the US Sarbanes-Oxley Act of 2002 (and associated rules) and the corporate governance rules set out in the Listed Company Manual of the New York Stock Exchange (“NYSE”).

Further details (including documents that can be downloaded) can be accessed on the corporate governance section of www.scottishpower.com.

Board Composition

The Board comprises the Chairman, two executive directors and six independent non-executive directors. It therefore meets the Combined Code requirement that at least half of the board, excluding the chairman, should comprise independent non-executive directors. Vicky Bailey and Nolan Karras will retire following the Annual General Meeting (“AGM”); accordingly this requirement will continue to be met.

Biographical details of the directors are set out on pages 48 and 49.

There is a clear division of authority at the most senior level within the company through the separation of the roles of Charles Miller Smith as Chairman and Philip Bowman as Chief Executive. The relationship between the two roles has been documented and agreed by the Board, creating an appropriate system of checks and balances.

Donald Brydon is the senior independent director and serves on the Board’s three principal standing committees. He acts as the presiding director at meetings of the independent directors and leads the performance evaluation of the Chairman. He is available to shareholders for concerns which have not been resolved by contact with the Chairman or Chief Executive or for which such contact is inappropriate.

The non-executive directors are drawn from diverse backgrounds and possess a broad range of experience encompassing business, financial services, regulation and community administration in the UK and US. This gives them the capacity to debate with and constructively challenge management both in relation to the development of strategy and in relation to operational and financial performance.

INDEPENDENCE

All of the non-executive directors are considered by the Board to be independent in character and judgement, having no material relationship with the company. As in prior years, the Board made this determination based on detailed questionnaires completed by all non-executive directors.

Last year the Board set out in detail its reasoning for regarding Nolan Karras and Nancy Wilgenbusch as independent. This explanation was provided because of connections between these directors and the company’s former subsidiary, PacifiCorp. The Board was cognisant of these matters but considered that they posed no threat to either director’s independence. That remains the view of the Board.

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Corporate Governance

APPOINTMENTS

The Nomination Committee has developed a robust process for the selection and recruitment of directors. Following a review of the Board’s size, composition and diversity, the Committee determines selection criteria and a role specification which is then passed to external selection consultants. The Committee reviews the profiles of identified candidates and interviews are conducted. The Committee then makes its recommendations to the Board for approval.

Directors stand for election by the shareholders at the first annual general meeting following their appointment and are subject to re-election at intervals of not more than three years thereafter. Decisions on re-election are informed by the results of the individual performance evaluation exercise.

Non-executive directors are appointed for a specified term of three years and re-appointment is not automatic. Taking into account the independence guidelines contained in the Combined Code, the company revised its policy during the year to provide that non-executive directors may serve for a maximum of three three-year terms. None of the current non-executive directors has served for more than two terms of office.

Board Effectiveness

DIRECTORS’ INDUCTION AND DEVELOPMENT

All newly appointed directors receive a structured induction, tailored to their requirements, to ensure they have the necessary knowledge and understanding of the company and its activities. At the time of appointment of new non-executive directors they are available to meet with shareholders on request.

Continuing professional development is provided through briefing sessions in the course of regular Board meetings, covering business-specific and broader regulatory issues.

BOARD PERFORMANCE EVALUATION

For the last three years the performance evaluation has been conducted using external facilitators. This year it was conducted internally, although external consultants may be used on a periodic basis in the future.

The internal evaluation followed a formal and structured process. The Chairman met with each of the directors to review the effectiveness of the Board and the Nomination Committee (which he chairs) and to conduct the individual evaluation. The chairmen of the Remuneration and Audit Committees held similar meetings with members of their own committees. The evaluation of the Chairman was led by the senior independent director following a private discussion of the non-executive directors and taking into account the views of the executive directors.

The evaluation recognised that the Board had taken a number of major and far-reaching decisions during the year and focused on the way the Board had reached these decisions and the support provided by the committees.

Reports were produced for the Board and each of the committees and considered at their March meetings. The outcomes of the evaluation exercise were positive and the Board considered the decisions it had taken during the year to be of high quality with good levels of teamwork, participation and debate. There was an acceptance of the need to place a renewed focus on the composition of the Board going forward. Other recommendations arising from the evaluation included, for example, methods of strengthening links and enhancing communication with independent advisers. The Nomination Committee also received a summary of the outcomes of

the individual evaluation as part of its broader consideration of those directors to be re-appointed and re-elected and the development needs of directors.

COMPANY SECRETARY

All directors have access to the advice and services of the Company Secretary who is responsible for ensuring that Board procedures are observed and for advising the Board on all corporate governance matters. The Company Secretary’s remit encompasses ensuring good information flows as well as facilitating the programme of directors’ induction and professional development and the Board performance evaluation exercise. The appointment and removal of the Company Secretary is a matter for the Board as a whole.

ADVICE AND INSURANCE

Directors can take independent professional advice at the company’s expense in the furtherance of their duties. The company has in place a directors’ and officers’ liability insurance policy that provides appropriate cover in respect of legal action brought against its directors. Article 159 of the company’s Articles of Association provides that every director or officer of the company shall be entitled to be indemnified by the company to the extent permissible under UK company law in respect of liabilities incurred in connection with their duties, powers or office. A deed of indemnity (in similar terms to Article 159) has been granted to each current director and officer of the company since July 2005. These indemnities are available for inspection by shareholders at the company’s registered office.

Board Proceedings

MEETINGS

The Board held seven scheduled meetings during the year, with an additional eight meetings to address specific issues. As part of this schedule, the Chairman meets with the non-executive directors and also the non-executive directors meet privately under the guidance of the senior independent director. Details of directors’ attendance at meetings of the Board and its Committees are set out in Table 30. The contribution of individual directors should not however be assessed solely by reference to the number of meetings attended.

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Board meetings involve reviews of operational, financial and safety performance (against the targets set by the Board) and risk management, both at a group level and for each of the businesses. They also cover strategic issues, business issues requiring decision (often in relation to capital expenditure projects) and other specific issues for decision or information. At each meeting, the Board receives an operational report from the Chief Executive and a financial and risk report from the Finance Director.

DECISIONS

The Board took three decisions during the year of major significance for the company: to sell PacifiCorp (returning cash to shareholders) and restructure the continuing group; to reject a takeover approach from E.ON; and to appoint a new Chief Executive. In each case the Board scrutinised all aspects of the proposal and devoted significant time to ensuring that the decision was in the best interests of the company and its shareholders. Taking the sale of PacifiCorp as an example, over the period from September 2004 to May 2005 the Board held a series of dedicated strategy sessions and additional meetings in order to review the different options with management and with financial and legal advisers.

GOVERNANCE FRAMEWORK

The Board has a formal schedule of matters reserved to it for decision, ensuring that the Board can exercise control over the key issues of strategy, investment and capital expenditure. A summary of this schedule can be accessed on the corporate governance section of www.scottishpower.com.

With the exception of these reserved matters, the full authority of the Board is delegated to the Executive Team.

EXECUTIVE TEAM

The Executive Team is constituted as a committee of the Board and comprises the executive directors along with key executives and officers responsible for the businesses and functions within the group (biographical details of Executive Team members are set out on pages 48 and 49). The Executive Team generally meets once a month and ensures executive focus on groupwide performance and risk management.

SOCIAL, ENVIRONMENTAL AND ETHICAL MATTERS

At each of its scheduled meetings, the Board receives an operational report from the Chief Executive describing developments across the group, including any relevant social, environmental and ethical (“SEE”) matters. Similarly, any SEE matters of significant importance are incorporated within the overall risk and control framework and included in the risk report. SEE matters are also included in the induction programme for directors. These mechanisms enable the Board to take account of the strategic significance of SEE matters to the group.

Further information regarding SEE matters can be found in Section 9 of the ‘Business Review’ and on the corporate responsibility section of www.scottishpower.com.

Reports from Committees

The Board is supported by three principal standing committees –the Nomination, Remuneration and Audit Committees. The Board has also established a Group Finance Committee, chaired by Nick Rose and comprising both executive and non-executive directors, which allows for detailed scrutiny of financing issues. It has authority to approve financing transactions within the strategy set by the Board.

Reports from the Nomination and Audit Committees are set out below and the activities of the Remuneration Committee are described in the Remuneration Report on pages 57 to 68. The

committees’ terms of reference are reviewed on an annual basis, and are available on the corporate governance section of www.scottishpower.com and on request from the Company Secretary. The Company Secretary acts as secretary to each of the committees.

NOMINATION COMMITTEE

The Nomination Committee is chaired by Charles Miller Smith. The other members are Donald Brydon, Nolan Karras and Nancy Wilgenbusch, all independent directors, and Philip

Table 30

Board and committee attendance during the year ended 31 March 2006

Charles Miller Smith (N*) Vicky Bailey (A) Euan Baird (R) Donald Brydon (N, R, A) Nolan Karras (N, R*, A) Nick Rose (R, A*) Nancy Wilgenbusch (N, R) Philip Bowman1 (N) Simon Lowth Philip Carroll2 (R, A) Ian Russell3 (N) Charles Berry4 David Nish5 Judi Johansen6

Board

15 15 9 13 13 12 12 2 15 6 12 5 8 14

(15

meetings)

Nomination

Committee 4 4 4 4 1 3

meetings)

Remuneration

Committee 5 9 10 8 9 4

(10

meetings)

Audit

Committee 9 9 9 8 3

meetings)

N – Nomination Committee R – Remuneration Committee A – Audit Committee

Committee Chairman

Philip Bowman was appointed in January 2006.

Philip Carroll retired in July 2005.

Ian Russell retired in February 2006.

Charles Berry retired in September 2005.

David Nish retired in September 2005

Judi Johansen retired in March 2006.

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Corporate Governance

Bowman, the Chief Executive. Following his appointment on 16 January 2006, Philip Bowman replaced Ian Russell on the Committee. The majority of the members of the Committee are independent non-executive directors.

The main functions of the Committee are to: review the structure, size and composition of the Board; identify and nominate candidates to fill Board vacancies; consider succession planning for directors; oversee the directors’ induction and training programme and the Board performance evaluation exercise; and keep under review developments in relation to corporate governance.

Only one Board appointment was made during the year, that of Philip Bowman as Chief Executive. Given the critical importance of this appointment, all of the non-executive directors were involved in the selection process and held extensive discussions on the issue led by the Chairman. External consultants were instructed to lead the search and constructed a short-list of candidates, from which two were selected for interview (conducted by the Chairman and senior independent director). Philip Bowman was identified as the preferred candidate and was subsequently interviewed by each of the remaining non-executive directors before being appointed at a meeting of the full Board.

During the year the Committee met on four occasions. The Committee kept under review the composition of the Board and its committees and considered issues of management change and succession, recommending the appointment of a new Finance Director and a new Company Secretary. In performance of its corporate governance role, the Committee adopted a revised policy on non-executive directors’ terms of office, received an update on those directors who completed their induction phase during 2005 and considered the results of the performance evaluation of individual directors.

AUDIT COMMITTEE

The Audit Committee is chaired by Nick Rose, who is also the identified “audit committee financial expert” for Scottish Power plc. The other members of the Committee are Vicky Bailey, Donald Brydon and Nolan Karras. Philip Carroll retired from the Committee on 22 July 2005. All of the members of the Committee are independent non-executive directors.

The main functions of the Committee are to: assess the effectiveness of the system of internal control and consider key risks facing the group and controls over these risks; review the company’s financial statements; consider the activities and effectiveness of the Internal Audit function; oversee the relationship with the external auditors, including the engagement of auditors, the audit scope and approach, fees and performance; assess compliance with legal and regulatory requirements; and review litigation and claims affecting the group.

Meetings of the Committee are normally attended by the Finance Director, the Group Director of Finance, the Director Group Internal Audit and representatives of the external auditors. However, the Committee holds regular private sessions to meet separately with senior management, representatives of Internal Audit and the external auditors.

During the year the Committee met on nine occasions. It reviewed the quarterly and annual results announcements of both Scottish Power plc and PacifiCorp and received quarterly reports on the work of the Internal Audit function, including the results of audits undertaken during the period and delivery of the audit plan. It also received more detailed presentations on risk and

control issues from the management of each of the businesses, allowing the Committee to question and challenge management directly on these issues.

The Committee received regular progress updates on the implementation of Section 404 of the Sarbanes-Oxley Act of 2002. It also monitored reports being received through internal and external whistleblowing channels and reviewed the group’s anti-fraud programme.

AUDITOR INDEPENDENCE

During the year the Audit Committee reviewed the independence and objectivity of the external audit firm. To prevent this independence being compromised policies are in place regarding the provision of non-audit services, and the hiring of former external audit staff. In line with best practice, the Audit Committee undertook a tender of the external audit contract in early 2006. Following a rigorous review process, it was agreed to recommend the appointment of Deloitte & Touche LLP as the group’s external auditor for the year ending 31 March 2007. A resolution to this effect will be put to shareholders for approval at the upcoming AGM.

The policy on non-audit services prohibits the use of the external audit firm for specified services. It is considered appropriate, for commercial and practical reasons including confidentiality, to use the external auditors for certain non-audit services. These permissible services are set out in the policy and have been pre-approved by the Audit Committee up to an initial fee value of £100,000 per assignment. Permissible services that are not listed in the policy require to be pre-approved individually by the Audit Committee or its Chairman; any assignments that exceed the fee limit must be reviewed and authorised by the Committee Chairman and the Finance Director.

Fees paid to the external auditors are shown in Table 31 opposite:

54 ScottishPower Annual Report & Accounts 2005/06

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Table 31

Auditors’ remuneration

2005/06

2004/05

£m

Audit

services

–

statutory audit 2.0 1.7

–

audit-related regulatory reporting 0.5 0.7

Further

assurance services 1.4 2.5

Tax

services

–

compliance services 1.2 1.0

–

advisory services 1.8 0.4

Other

services 0.1 –

Total

UK and US audit and non-audit fees

paid

to auditors 7.0 6.3

31 March 2005, fees for ‘Further assurance services’ principally relate to due diligence work on acquisitions and advice regarding the implementation of s404 of the Sarbanes-Oxley Act and the implementation of IFRS.

Safeguards are also in place to protect the independence of the Internal Audit department. The department reports directly to the Audit Committee; the Committee reviews the Internal Audit work plan and sets the department’s budget. In addition, the Committee is required to approve the appointment, replacement, reassignment or dismissal of the Director Group Internal Audit.

Internal Control and Risk Management

The overall responsibility for establishing and maintaining an adequate internal control system, and for setting the company’s risk management policy, rests with the Board. The effectiveness of the system is kept under continual review by the Audit Committee, acting on behalf of the Board, as part of a rolling work programme. This review encompasses financial, operational and compliance controls as well as risk management systems. Audit Committee papers and minutes are circulated to all members of the Board. In addition, the Audit Committee chairman updates the Board on the Committee’s deliberations after each meeting.

The Executive Team is responsible for implementing the risk management strategy; ensuring that an appropriate risk management framework is operating effectively across the group; embedding a risk culture throughout the group; and providing the Board and the Audit Committee with a consolidated view of the risk profile of the company, identifying any major exposures and mitigating actions.

The internal control system is designed to manage rather than eliminate risk, recognising that it can provide only reasonable and not absolute assurance against material misstatement or loss. The internal control system and risk management framework, which is subject to continuous

development, provides the basis on which the company has complied with the Combined Code provisions on internal control.

CONTROL ENVIRONMENT

The company’s commitment to controls and risk management is embedded within its culture and reflected in its policies. The organisational structure enables appropriate control of the businesses, with authority and accountability being delegated on a structured basis according to acceptable levels of risk.

The importance of acting with integrity and in a control conscious manner is communicated to all managers and employees. The company’s expectations in this regard are set out in Compliance

– Behaviour and the Law, a policy document that summarises the main legal, regulatory, cultural and business standards applicable to all employees. The company has also adopted a Code of Ethics for Principal Officers (this document can be accessed on the corporate governance section of www.scottishpower.com).

The company has in place an anti-fraud programme and procedures to ensure that all incidences of fraud are appropriately investigated and reported. This is supported by the company’s Speaking Out and Whistleblower Protection Policy, which incorporates a confidential, external reporting service operated by an independent provider. This policy provides for all reports made through the external service, and all other internal reports judged material, to be communicated to the Audit Committee.

A Disclosure Committee operates at management level to ensure effective disclosure controls are operating around the production of key published financial statements and to provide assurance to the Chief Executive and Finance Director that they may sign their formal certification to the SEC in accordance with Section 302 of the Sarbanes-Oxley Act of 2002.

IDENTIFICATION AND EVALUATION OF RISKS

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 risks associated with the achievement of its strategic objectives. Any key actions needed to enhance the control environment are identified, along with the person responsible for the management of the specific risk. A detailed review of the key risks, controls and action plans within each of the businesses takes place and a risk report is produced for review and challenge at the monthly meetings of the Business Risk and Investment Committees (see below).

A groupwide risk report setting out the top ten risks is prepared on a monthly basis and reviewed by the Executive Team. The Board also considers this report at its scheduled meetings.

Further details of risks can be found in Section 9.3 of the ‘Business Review’.

BUSINESS RISK AND INVESTMENT COMMITTEES

During the year, the Group Energy Risk Committee and the Group Investment Committee were disbanded and replaced with Business Risk and Investment Committees (“BRICs”). Operating within each of the businesses, the role of the BRICs is to maintain an overview of all matters of risk and capital management and undertake diligence as required. Membership

ScottishPower Annual Report & Accounts 2005/06 55

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Corporate Governance includes the business head and other senior business executives as well as corporate representation from the finance, strategy, risk management and legal functions.

MONITORING AND CORRECTIVE ACTION

The operation of the group’s control and monitoring procedures is reviewed and tested by the group’s Internal Audit function under the supervision of the Director Group Internal Audit, with a direct reporting line to the Audit Committee and to the Finance Director. Internal Audit reports and recommendations on the group’s procedures are reviewed regularly by the Audit Committee. The external auditors also provide reports to the Audit Committee on matters in relation to the group’s internal financial control procedures identified during the course of their audit. The Audit Committee also receives regular reports on the continued development, implementation and evaluation of the risk management and internal control system.

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES (SARBANES-OXLEY ACT OF 2002)

The Chief Executive and the Finance Director have evaluated the effectiveness of the group’s disclosure controls and procedures as at the end of the period covered by this report. Based on this evaluation, the Chief Executive and Finance Director concluded that the disclosure controls and procedures (as they are defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended) are effective.

During the year management has further improved the control environment in response to business change and developments in accounting practice. The application of IFRS has introduced more complexity to the group’s financial reporting processes principally in its treasury and energy management activities and management will continue to enhance processes and systems in these areas to support ongoing business needs. Furthermore, PPM Energy implemented a new integrated financial accounting system in March 2006 following the divestment of PacifiCorp. Management is now focused on embedding these new processes and systems within the PPM Energy business.

There has been no change to the group’s internal controls that has materially affected, or is reasonably likely to materially affect, these controls over financial reporting during the period covered by this report.

Communication with Shareholders

DIALOGUE

The company promotes dialogue with major investors through analysts briefings and investor roadshows in the UK, US and Europe. These presentations cover strategic issues as well as financial and operational performance. Broader shareholder communication takes place through the company’s website at www.scottishpower.com, and through the Annual Report & Accounts and the Annual Review.

The Board is kept informed of investors’ views principally through the distribution of analysts’ and brokers’ notes. In addition, the Board may commission periodic research. These are practical and effective methods of communicating shareholder opinion to the Board on a regular basis.

The Chairman and the senior independent director (and indeed other non-executive directors) are available to shareholders in the event of any concerns arising which cannot be addressed through management, or in connection with any significant change to the company’s strategy, remuneration policy or governance arrangements. The Chairman has held meetings with various investors during the year, with discussions including issues of strategy, management and governance. However, it is not the company’s practice for the Chairman or senior independent

director to hold such meetings routinely. As a result, the company has not strictly complied with the full requirements of Code provision D.1.1, although it is believed that, in practice, the objectives of the provision have been achieved.

AGM

The AGM gives shareholders the opportunity to consider the company’s financial and business performance as well as to question the Board on its stewardship of the company. It is normal practice for all directors to attend the AGM and be available to answer questions. Philip Carroll, who was retiring at the conclusion of the meeting, was unable to attend the AGM in 2005. All resolutions at the AGM are voted by poll, with full results (including the number of votes withheld) published following the close of the meeting.

NYSE Corporate Governance Rules

The NYSE requires listed companies incorporated in the US to comply with certain corporate governance rules. Foreign issuers such as ScottishPower are exempt from the majority of these requirements and may instead follow the practices prevailing in their home country. The practices followed by ScottishPower are very similar to those mandated by the NYSE with two primary exceptions: Nomination Committee composition – in line with UK practice, the Nomination Committee comprises a majority of independent non-executive directors, but does also include both the Chairman and Chief Executive. The NYSE rules suggest that all members of the committee should be independent; and Corporate Governance principles – UK listed companies are required either to comply with the Combined Code or explain why they have not done so. As a result, the Combined Code in effect provides a set of corporate governance principles for the company addressing all of the issues covered by the NYSE rules. ScottishPower has not, therefore, adopted company-specific corporate governance guidelines as suggested by the NYSE rules.

56 ScottishPower Annual Report & Accounts 2005/06

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Remuneration Report of the Directors

Consideration of Remuneration Matters by the Directors

Statement of Remuneration Policy

Elements of the Remuneration Package 2005/06

Consideration of Remuneration Matters by the Directors

The ScottishPower Board is responsible for determining the remuneration policy for the ScottishPower group. The Remuneration Committee, with delegated authority from the Board, determines the detail of remuneration arrangements for the Executive Team, including the executive directors, and reviews proposals in respect of other senior executives. The relationship between the Board and the Committee is based on formal terms of reference, which are available on the company’s website, and are regularly reviewed to ensure that they reflect best practice.

The Remuneration Committee consists solely of independent non-executive directors. Its members are Nolan Karras (Chairman), Euan Baird, Donald Brydon, Nick Rose and Nancy Wilgenbusch. Philip Carroll was a member, until his retirement from the Board at the AGM on 22 July 2005. Nolan Karras will retire from the board at the AGM on 26 July 2006, at which time he will be replaced as Chairman of the Committee by another independent non-executive director. These members have no personal financial interest, other than as shareholders, in the matters considered by the Committee. Details of the payments made to all non-executive directors are set out in Table 33 (page 63). The Chairman of the company, Charles Miller Smith, and the Chief Executive, Philip Bowman, are invited to attend meetings and may provide guidance on the impact of remuneration policy and advise, as appropriate, on the performance of senior executives. They are not present during any discussion of their own remuneration. The terms of reference contain conflict of interest provisions to ensure that no directors are involved in any decision relating to their own remuneration.

The Committee is able to draw on advice from independent remuneration consultants and internal expertise. Towers, Perrin, Forster & Crosby, Inc., (“Towers Perrin”) act as remuneration consultant and independent advisor to the Committee. Towers Perrin’s appointment by the Committee followed a competitive tendering exercise. Towers Perrin also provides remuneration and other human resources consultancy services directly to some ScottishPower companies within parameters established by the Committee. The terms of reference of the independent remuneration advisors are available on the company’s website. Company executives whom the Committee may consult include the Company Secretary, (who acts as Secretary to the Committee) and the Director, Human Resources & Communications. The terms of reference of the Remuneration Committee empower it to avail itself of external legal and professional advice at the expense of the company. In accordance with the terms of reference, the Committee received advice from Freshfields Bruckhaus Deringer (the company’s legal advisers) on a number of matters in the year to 31 March 2006.

The Committee met on ten occasions during the year ended 31 March 2006.

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

Statement of Remuneration Policy

PHILOSOPHY AND POLICY

ScottishPower seeks to ensure that remuneration and incentive schemes are in line with best practice, provide a strong link to individual and company performance and promote a community of interest between employees and shareholders.

ScottishPower Annual Report & Accounts 2005/06 57

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Remuneration Report of the Directors

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

Annual bonus arrangements have been structured so that stretching targets are based on corporate, business unit and individual performance.

The company operates a Personal Shareholding Policy (“PSP”), requiring executives and key senior managers to buildup and retain a shareholding in the company in proportion to their annual salaries. The proportion is two times base salary for Philip Bowman and Simon Lowth. The Committee expects PSP participants to have accumulated their respective shareholding targets within eight years of the introduction of the policy, that is by the end of May 2008, or eight years after their first award under any discretionary share plan for external appointees to the Board.

In setting remuneration levels, the Committee commissions an independent evaluation of the roles of the Executive Team. The Committee takes independent advice from Towers Perrin on market-level remuneration, based on comparisons with other companies of similar size and complexity, including the major utility companies, with which the company competes for executive talent.

The Committee recognises the importance of linking rewards to business and personal performance and believes that the arrangements detailed below provide an appropriate focus on performance and balance between short- and long-term incentives. The annual bonus plan and long-term incentive arrangements are expected to provide 51% – 59% of total remuneration for the achievement of stretching target objectives. Higher proportions of performance-based reward are available for the delivery of exceptional personal and business performance resulting in enhanced shareholder value.

The Committee constantly monitors market practice in order to remain competitive, to ensure that reward policy supports company strategy and to reflect good corporate governance practice. The Long Term Incentive Plan (“LTIP”) expires at the 2006 AGM having reached the end of its ten-year lifespan. The Committee has therefore undertaken a thorough review of total remuneration and, after consultation with major shareholders, has developed a new long-term incentive plan which will be put to shareholders for approval at the 2006 AGM. The proposals will (subject to shareholder approval) strengthen the link between remuneration and performance, and put more weight on long-term performance. Details of the proposed new long-term incentive arrangements can be found in the Notice of AGM. At this time, no other substantial changes to the company’s policies with regard to directors’ remuneration are envisaged over the next year. However, the Committee may develop policy and, should it determine any changes to be appropriate, will report such changes to shareholders through established channels of consultation and reporting.

Elements of the Remuneration

Package 2005/06

BASE SALARIES

The Committee sets base salaries for the Executive Team by reference to individual performance through a formal appraisal system applied to all management employees, and to external market data, reflecting similar roles in comparable companies. Account is also taken of salary increases and employment conditions across the company.

ANNUAL PERFORMANCE-RELATED BONUS

The Executive Directors are entitled to participate in an annual bonus scheme. The maximum annual bonus under this scheme for Philip Bowman was 37.5% of his basic annual salary for the period from his appointment up to 31 March 2006 and thereafter, 150% of his basic annual salary. The maximum bonus for Simon Lowth is 100% of his basic annual salary of which 75% is to be paid immediately in cash and 25% deferred and payable in shares which are released after three years.

For the 2005/06 annual incentive plan, Philip Bowman’s bonus was based on an assessment of his contribution and impact since joining. For Simon Lowth, bonus was based on the achievement of key financial targets, strategic objectives, the relevant business scorecard and leadership behaviours.

For the 2006/07 annual incentive plan, both executive directors’ bonus will be based at least 65% on key company financial metrics (including EBIT, net debt and working capital), with the remainder on key personal objectives and leadership behaviours.

EXECUTIVE SHARE PLANS

During 2005/06 the company operated one long-term incentive, a performance share plan, known as the LTIP for executive directors and other senior managers. The final awards under the LTIP were made in May 2005 with a special award granted to Philip Bowman on terms equivalent to the LTIP in March 2006 following his appointment. In May 2004, the company made the final award under the Executive Share Option Plan 2001 (“ExSOP”).

Under the LTIP, awards to acquire shares in ScottishPower at nil or nominal cost were made to the participants up to a maximum value, at the time of grant, equal to 75% of base salary (100% for Philip Bowman). The award will vest only if the Committee is satisfied that there has been sustained underlying performance of the company and, to this end, certain gateway

58 ScottishPower Annual Report & Accounts 2005/06

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performance targets are measured and the Committee reviews performance against these measures when determining if awards vest. The measures relate to the key financial performance indicators of the company and customer service standards. These measures provide a mechanism to safeguard stakeholder interests and provide an overview of the financial and operational success of the business.

The number of shares which actually vest is dependent upon the company’s comparative Total Shareholder Return (“TSR”) performance, over a three-year performance period. TSR measures ScottishPower’s comparative performance against key competitors and provides rewards only if ScottishPower is at least equal to the median performance of appropriate comparators. The Committee chose TSR as the performance measure for the LTIP as it believes that it provides a clear link to the creation of shareholder value.

LTIP awards were granted to 60 directors and senior executives during the year (Award 10). TSR performance is measured against an international comparator group of 37 major energy companies, as identified below.

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

No shares vest unless the company’s TSR performance is at least equal to the median performance of the comparator group, at which point 40% of the initial award vests. 100% of the shares vest if the company’s performance is equal to or exceeds the top quartile. The number of shares that vest for performance between these two points is determined on a straight-line basis.

For LTIP Award 7, which had the potential to vest during the year, TSR performance was measured against a similar composition of international energy companies over the three year period to 31 March 2005. After careful consideration, the Committee determined that the gateway measures relating to the financial and customer service performance of the company had been achieved. As the company was ranked 18th against the comparator group, 50% of the initial award vested. This meant that at the maximum level of participation whereby awards were made over shares with an initial value of 75% of base salary at May 2002, an award equal to 37.5% of base salary at May 2002, became available for exercise by participants in May 2005.

The Committee is recommending a new long-term incentive plan for approval at the 2006 AGM. The key features of the proposed plan are as follows:

annual grants of performance-vesting shares;

vesting based on three-year TSR against a group of 12 UK utilities weighted by market capitalisation;

30% vesting at median performance and 100% vesting at 70th percentile performance; and

maximum grant sizes of 100% of salary in 2006, 125% in 2007 and 150% in 2008.

Full details of the proposed new long-term incentive plan can be found in the Notice of AGM.

PERFORMANCE GRAPH

The Directors’ Remuneration Report Regulations require that a graph be presented showing the company’s TSR performance against the TSR performance of a broad equity market index over a five-year period. The FTSE 100 has been chosen because it is the principal index in which the company’s shares are quoted. The graph below presents the comparative TSR performance of the company during the period 1 April 2001 – 31 March 2006. The graph shows that ScottishPower has outperformed the index over this period.

This graph looks at the value (net of witholding tax), at 31 March 2006, of £100 invested in ScottishPower on 31 March 2001 compared with that of £100 invested in the FTSE 100 Index. The other points plotted are the values at intervening financial year ends.

ALL-EMPLOYEE SHARE PLANS

To facilitate high levels of share ownership by employees, the company operates two savings-related share ownership plans to which executive directors may contribute. These are all employee Inland Revenue approved plans and are not subject to performance conditions. Participation is available to executive directors on the same basis as to all other eligible employees.

SHARESAVE

Employees domiciled in the UK are eligible to participate in the ScottishPower all-employee Sharesave plan. Under this plan, options are granted over ScottishPower shares at a discount of 20% from the prevailing market price at the time of grant to

TOTAL SHAREHOLDER RETURN

Scottish Power plc

FTSE 100 Index

31March

125

150

175

ScottishPower Annual Report & Accounts 2005/06 59

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Remuneration Report of the Directors

eligible employees who commit to save up to £250 per month over a period of three or five years.

EMPLOYEE SHARE OWNERSHIP PLAN (“ESOP “)

The company operates an ESOP (also known as a Share Incentive Plan) for all UK domiciled employees. The ESOP enables employees to purchase shares in the company from pre-tax income up to the limits specified in the legislation. The value of these shares is at risk as they are not normally released until the legislation allows. The company matched these shares at no cost to the employee on a one-for-one ratio. With effect from 1 April 2006 the company match is reduced to a maximum value of £50.

RETURN OF CASH

The company’s recent Return of Cash process had no impact on shares held within ExSOP, LTIP and Sharesave. Shares already purchased within the ESOP were subject to the same treatment as ordinary shareholders and will thus be divided into ordinary shares and B shares.

PENSION

Simon Lowth and other senior managers 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 at retirement age, less retained benefits, reduced where service to normal retirement age is less than 20 years. Pensionable salary is normally base salary in the 12 months prior to leaving the company although there are prescribed mechanisms for calculating pensionable salary by averaging base salary over a period of up to three out of the last 10 years’ service. The employee contributes 5% of salary to the scheme. Life assurance provision of four times pensionable salary and a widow’s pension of half the executive’s pension on death are provided.

Individuals who joined the company on or after 1 June 1989 are subject to an ‘earnings cap’, equivalent to the HM Revenue and Customs ‘earnings cap’ that was introduced by the Finance Act 1989. Entitlement to pension benefits above the cap are not provided through the company’s approved pension scheme, and therefore arrangements on an unapproved basis have been made to provide total benefits for executives as though there was no cap. The total liability calculated on an IAS 19 basis in respect of executives and senior employees arising in relation to unapproved benefits accrued for service for the year to 31 March 2006 was £1,238,000. As part of the continuing drive to improve the cost effective delivery of pensions, the company and the trustees agreed to the merger of the approved Executive Top-Up Plan into the main ScottishPower Pension Scheme.

Philip Bowman receives a cash allowance in lieu of pension, equal to 50% of basic annual salary and payable monthly. He has no right to participate in any pension schemes. He also receives life assurance provision of four times basic annual salary.

The Committee has considered, at length, the company’s response to the government’s simplification of the pensions taxation regime that took effect on 6 April 2006 (‘A-day’). In determining future executive pensions policy, the Committee ensured that no additional benefit would accrue to executive directors as a result of the taxation reform. The Committee has decided that the unapproved promise will remain the sole vehicle for providing executive pensions above the new Life Time Allowance.

The Committee has reported the pension expense in accordance with the requirements of the UK Listing Authority and Directors’ Remuneration Report Regulations. Pension costs detailed in the Accounts are calculated as the cost of providing benefits accrued in the 2005/06 year, in accordance with appropriate accounting standards.

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 or a cash allowance in lieu of a car, fuel and private medical provision. The provision and level of benefits is reviewed regularly to ensure that practice is in line with the market.

EXTERNAL NON-EXECUTIVE APPOINTMENTS

The company encourages its Executive Directors to become non-executive directors of other companies, provided that these appointments 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 Chairman and the executive directors of the Board and consists of a base fee of £31,000 p.a., a committee membership fee of £5,000 p.a. (not paid to a committee chairman), a fee of £15,000 p.a. for chairing the Audit Committee and the Remuneration Committee, and an international travel fee of £1,000 for attending a tranche of meetings that involve a transatlantic journey.

A fee of £10,000 p.a. is paid for chairing the Group Finance Committee of the Board and £3,000 p.a. to be a member. Such fees are only paid to the independent non-executive directors who serve on the Group Finance Committee.

A fee of £10,000 p.a. is also payable for the role of senior independent director.

In line with best practice, the independent non-executive directors do not have service contracts, but are appointed under standard letters of appointment. They are not members of the company’s pension schemes and do not participate in any bonus,

60 ScottishPower Annual Report & Accounts 2005/06

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TABLE 32

Service contracts

Contract element Philip Bowman Simon Lowth Ian Russell/Charles Berry/David Nish

Date 31 March 2006 1 August 2003 3 June 2003

Notice period Terminable by giving ScottishPower (“SP”) 12 months’ notice, and initially by SP giving 24 months’ notice, which will reduce by one month in each of the 12 months following his appointment so that the period of notice at any time on or after 16 January 2007 is 12 months Terminable by either party giving the other 12 months’ notice. Terminable by either party giving the other 12 months’ notice.

Basic annual salary Reviewable annually from April 2007 Reviewable annually Reviewable annually

Termination SP has a discretion to terminate the service agreement immediately by making a payment in lieu of notice of a prescribed amount. If SP terminates the service agreement unlawfully, SP is obliged to pay liquidated damages to the director of the same prescribed amount.

Payment in lieu of notice/ liquidated damages Calculated by reference to basic salary, any allowance in lieu of pension provision, pension benefits and all other contractual benefits (excluding pension provision, bonus and share related incentives) which the Executive Director would have been entitled to receive or accrue during a period equivalent to notice period.

Mitigation SP has a discretion to pay any amount in respect of liquidated damages in full on termination of employment or in instalments. 75% will be paid on termination of the employment and 25% will be paid nine months following termination of the employment. If Philip Bowman takes up alternative employment prior to nine and twelve months following termination, any further instalment payment due will be reduced by the salary he receives from that other employment for the period nine and twelve months following termination. SP has a discretion to pay any amount in respect of liquidated damages in full on termination of employment or in instalments. 50% will be paid on termination of the employment, 25% will be paid six months after termination of the employment and the balance will be paid nine months following termination of the employment. If Simon Lowth takes up alternative employment between six and nine months following termination, any further instalment payments due will be reduced by the salary he receives from that other employment. SP has a discretion to pay any amount in respect of liquidated damages in full on termination of employment or in instalments. 50% will be paid on termination of the employment, 25% will be paid six months after termination of the employment and the balance will be paid nine months following termination of the employment.

Future bonus Where a payment in lieu of notice or a liquidated damages payment is made, SP will pay an amount to the director representing a percentage of his maximum annual bonus for the relevant bonus year or years that the notice period may span. The percentage of bonus will be determined by the Remuneration Committee having regard to the performance of SP against its pre- determined financial objectives for the relevant bonus year(s) and must be consistent with any determination made in respect of other employees of similar status and seniority. The bonus amount will be paid at the same time as annual bonuses are paid to other employees. The amount may be reduced if the director obtains alternative employment during the notice period to take account of any bonus payable to the director for that period from the alternative employment.

Other If a change of control of SP occurs (other than by way of an internal reorganisation) prior to 16 January 2009, Philip Bowman may, within three months of that change of control, terminate his employment by giving SP 28 days’ notice. If either Philip Bowman or SP terminates the employment within such three month period, Philip Bowman will be entitled to immediate payment of a lump sum liquidated damages payment calculated on the basis described above. In addition, any bonus payable to Philip Bowman after such termination will not be reduced by any bonus obtained from any alternative employment that he may obtain.

Cessation If not otherwise terminated, the service contracts terminate automatically at Normal Retirement Age.

Former US Director Judi Johansen had a service contract dated 1 October 2003 on similar terms to those above for Simon Lowth. In addition, on completion of the

PacifiCorp sale, she becomes entitled to a cash retention award conditional upon there being no breach of warranty under the Stock Purchase Agreement with MidAmerican. The company’s policy is that all new directors will be offered service contracts on the terms outlined above as they apply to Simon Lowth.

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.

The Chairman, Charles Miller Smith, does not have a service contract with the company.

ScottishPower Annual Report & Accounts 2005/06 61

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Remuneration Report of the Directors

share option or other profit or long-term incentive plan. Full details of the remuneration of the non-executive directors are contained in Table 33.

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 company to all directors and officers, as a group, was £22,389,800. This includes termination payments to directors and officers made in 2005/06.

During 2005/06 the cost to 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 £4,055,000 (calculated in accordance with IAS 19).

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 ExSOP and Sharesave Scheme and awards under the LTIP, are shown on pages 65 to 68.

DIRECTORS’ EMOLUMENTS

Table 33 provides a breakdown of the total emoluments of the Chairman and all the directors in office during the year ended 31 March 2006.

DIRECTORS’ PENSION BENEFITS

Details of pension benefits earned by the executive directors during the year are shown in Table 34.

The following tables provide details of the remuneration, pensions and share interests of the directors and the information is audited.

62 ScottishPower Annual Report & Accounts 2005/06

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TABLE 33

Directors’ emoluments 2005/06

Basic salary £000s Bonuses £000s Pension allowance £000s Benefits in kind*** Compensation/ payment in lieu of notice**** £000s Total £000s

Total emoluments 2006 2005 2006 2005 2006 2005 £000s 2005 2006 2006 2005

Chairman and executive directors

Charles Miller Smith (Non-Executive Chairman) 317.4 275.0 — — — — — — — 317.4 275.0

Philip Bowman (appointed 16 January 2006) 146.8 — 262.5 — 73.4 — 1.9 — — 484.6 —

Simon Lowth 450.0 430.0 438.8 354.8 — — 16.1 16.1 — 904.9 800.9

Ian Russell (retired 16 February 2006) 648.2 705.0 — 627.5 — — 28.0 47.6 2,311.6 2,987.8 1,380.1

Charles Berry (retired 6 September 2005) 187.2 400.0 — 382.0 — — 12.5 37.7 1,224.5 1,424.2 819.7

David Nish (retired 6 September 2005) 235.1 430.0 — 387.0 — — 12.9 41.8 1,263.1 1,511.1 858.8

Judi Johansen* (retired 21 March 2006) 442.6 406.3 — 213.3 — — — 11.5 442.6 885.2 631.1

Fees £000s Bonuses £000s Pension allowance £000s Benefits in kind*** £000s Compensation/ payment in lieu of notice**** £000s Total £000s

2006 2005 2006 2005 2006 2005 2006 2005 2006 2006 2005

Non-executive directors (fees and expenses)

Vicky Bailey 42.0 34.5 — — — — — 2.2 — 42.0 36.7

Euan Baird 39.0 37.0 — — — — — — — 39.0 37.0

Donald Brydon 59.0 53.8 — — — — — 13.4 — 59.0 67.2

Philip Carroll (retired 22 July 2005) 18.0 55.0 — — — — — 0.6 — 18.0 55.6

Nolan Karras** 68.0 64.3 — — — — — — — 68.0 64.3

Nick Rose 61.7 55.1 — — — — — 11.8 — 61.7 66.9

Nancy Wilgenbusch** 52.4 39.9 — — — — — — — 52.4 39.9

Other emoluments

Conversion rate used for Judi Johansen is £1 = $1.785, being the average exchange rate during the year

** Nolan Karras and Nancy Wilgenbusch received emoluments in the US of £8,964 (2005: £8,667) and £8,403 (2005: £2,709) respectively. These amounts relate to services to the PacifiCorp Utah and Pacific regional advisory boards and were paid in the form of cash and shares prior to the sale of PacifiCorp. The amounts are included within ‘Fees’ in the above table.

*** Directors are eligible for a range of benefits on which they are assessed for tax. These include the provision of a company car or a cash allowance in lieu of a car, fuel and private medical provision.

**** Compensation/Payment in lieu of notice:

Charles Berry, David Nish and Ian Russell

Charles Berry and David Nish ceased to be employed by the company on 16 September 2005. Ian Russell ceased to be employed on 16 February 2006. Following the termination of their employments with the company, each of Charles Berry, David Nish and Ian Russell became entitled to a payment in lieu of notice in accordance with the terms of their service contracts. The total initial amount payable includes compensation for loss of basic salary, pension and other benefits. The company exercised its discretion to pay these amounts in instalments and so Charles Berry, David Nish and Ian Russell have each received a payment in respect of 50% of the initial compensation amount. Further payments of 25% of the initial compensation amount may be made six months and nine months after the relevant termination date but these payments will be reduced by any salary which the former director receives from any employment he enters into in the meantime. Charles Berry and David Nish have been paid the second 25% instalment without a reduction. In addition and in line with the Company’s financial performance, each former director received a payment in respect of his bonus entitlement for the 2005/06 financial year equal to 90% of their maximum opportunity and a pro-rated payment in respect of his bonus entitlement for the 2006/07 financial year. The maximum bonus payable is 100% of basic salary. The payment in respect of bonus for the 2006/07 financial year will be reduced by any bonus receivable by the former director from any employment which he enters into before payment. The payment of any such sum shall be made on the date annual bonus payments are made to other employees for that bonus year.

The company has also made, or has agreed to make, payments relating to legal fees and outplacement counselling fees.

The figures shown above under ‘Compensation/Payment in lieu of notice’ represent compensation for loss of basic salary, pension, benefits, legal/outplacement fees, bonus for 2005/06 and an estimated bonus for 2006/07.

Judi Johansen

Judi Johansen’s employment with PacifiCorp terminated immediately following the completion of the sale of PacifiCorp on 21 March 2006 and she became entitled to a compensation payment in accordance with her service contract (as amended). Judi Johansen received 50% of this payment within 30 days of completion of the sale of PacifiCorp. The remaining 50% may be paid 6 months after the termination date but if Judi Johansen takes up alternative employment in the meantime the second payment will be reduced by the salary and bonus receivable from that alternative employment. These payments will be paid by PacifiCorp. Judi Johansen has agreed that following her termination, and if required, she will provide ad hoc support to ScottishPower. The company has agreed that the second instalment of her compensation payment will not be reduced by any fee payable for this work.

On completion of the sale of PacifiCorp, Judi Johansen became entitled to a payment from the company of £354,062, being 80% of the cash retention award due for successful completion of the sale of PacifiCorp. Judi Johansen remains entitled to payment from the company of £88,515, being 20% of the cash retention award, 12 months after her termination date, provided there have been no breach of warranty under the Stock Purchase Agreement with MidAmerican during that time. These payments will be made by ScottishPower.

Charles Berry, David Nish, Ian Russell and Judi Johansen also received good leaver status under the ExSOP and LTIP. Under ExSOP, all outstanding options become immediately exercisable without the need to fulfil pre-determined performance conditions. Under LTIP, directors may receive shares at the end of the performance period should the performance conditions be satisfied. Any award made will be reduced to reflect the amount of time they were in post during the performance period.

(i) The emoluments of the highest paid director (Ian Russell) excluding pension contributions were £2,987,823 (2005: £1,380,079). Details of share related incentives are contained in Tables 35 and 36.

(ii) Ian Russell has an entitlement under the unapproved pension benefits described further in Table 34.

ScottishPower Annual Report & Accounts 2005/06 63

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Remuneration Report of the Directors

TABLE 34

Defined benefits pension plans 2005/06

Year Benefits recognised in respect of previous employments (see note viii) £ p.a. Additional pension earned in year (net of inflation) £ p.a. Accrued pension at end of year £ p.a. (A) Transfer value of increases after inflation (net of director’s contribution) £ Value of accrued pension at start of year £ Value of accrued pension at end of year £ (B) Total change in value during the year (net of director’s contributions) £

Simon Lowth 36,185 13,862 68,568 170,322 530,246 833,963 298,438

Ian Russell1 31,294 18,722 270,498 476,816 3,385,630 6,821,422 3,430,952

Charles Berry2 11,887 12,124 166,077 300,292 2,125,091 4,155,803 2,028,072

David Nish3 12,720 6,101 100,189 138,369 1,033,723 2,297,930 1,262,006

Judi Johansen4 — 83,901 145,482 715,871 261,243 1,328,962 1,067,719

1 Ian Russell retired on 16 February 2006. The figures shown above relate to the period between 1 April 2005 and the date of leaving. Under the rules of the Pension Scheme, he is entitled to unreduced benefits. The value of retiring early on an unreduced pension amounts to £2,664,727 which is included in the figure shown in the final column.

2 Charles Berry retired on 6 September 2005. The figures shown above relate to the period between 1 April 2005 and the date of leaving. Under the rules of the Pension Scheme, he is entitled to unreduced benefits. The value of retiring early on an unreduced pension amounts to £1,399,862 which is included in the figure shown in the final column.

3 David Nish retired on 6 September 2005. The figures shown above relate to the period between 1 April 2005 and the date of leaving. Under the terms of his contract, he is entitled to unreduced benefits from age 50. The value of retiring early on an unreduced pension when he reaches age 50 amounts to £847,510 which is included in the figure shown in the final column. Pension rights accrued in respect of previous employments affect the level of benefits available under the ScottishPower pension arrangements. The value of these rights, as a proportion of the benefits provided by ScottishPower, may change over time e.g. due to changes in an individual’s salary. Such changes in value are crystallised on the exit of a member and can lead to significant reductions or increases to accrued pension. These distortions have been removed from the figures shown in the table for David Nish by restating the end year accrued pension figures that appeared in the prior year Remuneration Report of the Directors. This ensures that the figures are calculated on a consistent basis and show the true value of pension benefits earned over the current accounting period.

4 Judi Johansen retired on 21 March 2006. The figures shown above relate to the period between 1 April 2005 and the date of leaving. The capital value of her pension entitlement triggered by her termination is £652,815. In addition, under the normal provisions of the plan she is entitled to benefits that commence from age 55. The value of this reduction in retirement age is £320,157. Both of these values are included in the figure shown in the final column. Part of Judi Johansen’s benefits are provided in defined contribution form, through a company 401(k) plan. The figures in the table do not include any 401(k) plan element. The company contribution payable to the 401(k) plan in respect of Judi Johansen for the period 1 April 2005 to 21 March 2006 was £7,199. The conversion rate used is £1 = $1.785, being the average exchange rate during the year. All pension amounts are payable by PacifiCorp.

(i) The accrued entitlement of the highest paid director (Ian Russell) was £270,498 (2005: £246,803). During the year, retirement benefits were accrued under the defined benefits pension scheme in respect of five directors (2005: five directors).

(ii) The transfer value of the increases after inflation (A) represents the current capital sum which would be required, using demographic and financial assumptions, to produce an equivalent increase in accrued pension and ancillary benefits, excluding the statutory inflationary increase, and after deduction of members’ contributions.

Although the transfer value represents a liability to the Pension Scheme in respect of approved benefits and to the company in respect of any unapproved benefits, it is not a single sum paid or due to be paid to the individual director and cannot therefore meaningfully be added to the annual remuneration. Instead, this value would not be payable until the director’s retirement date, and thereafter would be spread over the remainder of his lifetime (and also covering the cost of dependants’ benefits after his death).

(iii) The total change in value (B) in the last column of the table above reflects the following elements:

1. changes to the economic and demographic assumptions underlying the transfer value basis over the year; 2. any increases in pensionable salary received during the year; 3. the completion of further pensionable service during the year; and

4. the directors are a year closer to drawing their pensions, which increases their pension value (all other things being equal).

The change in the amount of the transfer values over the year includes the effect of fluctuations in factors that are beyond the control of the company and its directors, such as stockmarket movements and long-term interest rates.

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

(v) Directors who joined the UK pension scheme on or after 1 June 1989 are subject to an earnings cap equivalent to the HM Revenue and Customs earnings cap that was introduced by the Finance Act 1989. Pension entitlements which cannot be provided through the company’s approved schemes, due to the earnings cap, are provided through unapproved pension arrangements, details of which are included in this section. The pension benefits disclosed above include approved and unapproved pension arrangements.

(vi) The increase in UK accrued pension during the year excludes the increase due to RPI inflation as measured at December 2005 (2.2%).

(vii)The value of directors’ UK entitlements has been calculated on the basis of actuarial advice in accordance with Actuarial Guidance note GN11, in two parts: the approved element being based upon the normal cash equivalent transfer value assumptions; the unapproved element being calculated in line with IAS 19 assumptions. The value of the US director’s entitlement has been calculated in line with IAS 19 assumptions.

(viii)Benefits recognised in respect of previous employments covers both transferred in benefits and benefits that are held outside the ScottishPower pension arrangements.

The accrued pension shown at the end of the year, and the additional pension earned in the year, include these benefits.

Pension rights accrued in respect of previous employments affect the level of benefits available under the ScottishPower pension arrangements. The value of these rights, as a proportion of the benefits provided by ScottishPower, may change over time e.g. due to changes in an individual’s salary. Such changes in value are crystallised on the exit of a member and can lead to significant reductions or increases to accrued pensions.

(ix) The total liabilities, calculated on an IAS 19 basis, arising in relation to UK unapproved benefits for all executives and senior employees in the ScottishPower group for service in the year to 31 March 2006 was £1,238,000 (2005: £1,520,900). This figure relates only to the cost of benefits accruing over the year but does not include any finance items or past service costs. It therefore differs from the full IAS 19 charge for unapproved benefits over the same period.

(x)

All benefits above are provided on a defined benefit basis.

64 ScottishPower Annual Report & Accounts 2005/06

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TABLE 35

Directors’ interests in ScottishPower shares

Ordinary shares Share options (Executive) Share options (Sharesave) Long Term Incentive Plan

31.3.06 (or date of retirement, if earlier) 1.4.05 (or date of appointment, if later) 31.3.06 (or date of retirement, if earlier) 1.4.05 (or date of appointment, if later) 31.3.06 (or date of retirement, if earlier) 1.4.05 (or date of appointment, if later) 31.3.06 (or date of retirement, if earlier) 1.4.05 (or date of appointment, if later)

**Vested *Potential **Vested *Potential

Charles Miller Smith 11,000 11,000 — — — — — — — —

Vicky Bailey — — — — — — — — — —

Euan Baird 114,363 114,363 — — — — — — — —

Donald Brydon 3,000 3,000 — — — — — — — —

Philip Carroll (retired 22 July 2005) 4,000 4,000 — — — — — — — —

Nolan Karras 44,578 42,446 — — — — — — — —

Nick Rose 5,629 5,395 — — — — — — — —

Nancy Wilgenbusch 2,177 508 — — — — — — — —

Philip Bowman (appointed 16 January 2006) — — — — — — — 119,148 — —

Simon Lowth 28,868 17,710 220,937 220,937 3,534 — — 151,908 — 82,851

Ian Russell (retired 16 February 2006) • 148,653 128,280 1,206,427 1,206,427 5,290 5,290 108,572 378,628 58,047 367,006

Charles Berry (retired 6 September 2005) • 57,000 41,712 628,407 628,407 2,533 2,941 27,559 204,100 — 195,279

David Nish (retired 6 September 2005) • 49,394 36,415 738,171 738,171 2,533 — 32,152 234,632 — 230,230

Judi Johansen (retired 21 March 2006) 140,025 103,331 290,880 496,500 — — 18,497 192,851 — 166,289

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 LTIP award becomes exercisable calculated according to the performance criteria measured over the three-year performance period.

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

Free shares Partnership shares Matching shares Dividend shares Total

31.3.06 (or date of retirement, if earlier) 1.4.05 31.3.06 (or date of retirement, if earlier) 1.4.05 31.3.06 (or date of retirement, if earlier) 1.4.05 31.3.06 (or date of retirement, if earlier) 1.4.05 31.3.06 (or date of retirement, if earlier) 1.4.05

Ian Russell (retired 16 February 2006) 50 50 1,827 1,580 1,827 1,580 566 430 4,270 3,640

Charles Berry (retired 6 September 2005) 50 50 1,738 1,580 1,738 1,580 490 430 4,016 3,640

David Nish (retired 6 September 2005) 50 50 1,738 1,580 1,738 1,580 490 430 4,016 3,640

Between 31 March 2006 and 19 May 2006, Nolan Karras and Nancy Wilgenbusch acquired 86.5266 and 29.8200 ScottishPower ADSs (346 and 116 ordinary shares) respectively as part of the PacifiCorp Compensation Reduction Plan. Otherwise, there have been no changes to the directors’ interests between 31 March 2006 and 19 May 2006.

In accordance with the terms of the return of cash approved by shareholders on 4 May 2006, with effect from 15 May 2006 the ordinary shares detailed above in Table 35 were replaced by new ordinary shares and B shares. Under the terms of the return of cash, a holder of 100 existing ordinary shares on the record date, 6pm on 12 May 2006, received 79 ordinary shares, 33 B shares and, if applicable, cash representing any fractional entitlements to new ordinary shares.

ScottishPower Annual Report & Accounts 2005/06 65

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Remuneration Report of the Directors

TABLE 36

Directors’ interests in performance and other share plans at 31 March 2006

1 April 2005 (or date of appointment, if later) Granted Exercised Lapsed# 31 March 2006 (or date of retirement, if earlier) Option exercise price (pence) Date exercised Market price at date of exercise (pence) Date from which ordinarily exercisable Normal expiry date

Long Term Incentive Plan

Philip Bowman (appointed 16 January 2006) — 119,148 — — 119,148 nil 26 May 08 25 May 12

— 119,148 — — 119,148

Simon Lowth 82,851 — — — 82,851 nil 27 May 07 26 May 11

— 69,057 — — 69,057 nil 26 May 08 25 May 12

82,851 69,057 — — 151,908

Ian Russell+ (retired 16 February 2006) 21,217 — — — 21,217 nil 05 May 04 04 May 07

36,830 — — — 36,830 nil 04 May 04 03 May 08

101,600 — — 51,075 50,525 nil 02 May 05 01 May 09

129,568 — — — 129,568 nil 10 May 06 09 May 10

135,838 — — — 135,838 nil 27 May 07 26 May 11

— 113,222 — — 113,222 nil 26 May 08 25 May 12

425,053 113,222 — 51,075 487,200

Charles Berry+ (retired 6 September 2005) 55,418 — — 27,859 27,559 nil 02 May 05 01 May 09

62,790 — — — 62,790 nil 10 May 06 09 May 10

77,071 — — — 77,071 nil 27 May 07 26 May 11

— 64,239 — — 64,239 nil 26 May 08 25 May 12

195,279 64,239 — 27,859 231,659

David Nish+ (retired 6 September 2005) 64,655 — — 32,503 32,152 nil 02 May 05 01 May 09

82,724 — — — 82,724 nil 10 May 06 09 May 10

82,851 — — — 82,851 nil 27 May 07 26 May 11

— 69,057 — — 69,057 nil 26 May 08 25 May 12

230,230 69,057 — 32,503 266,784

Judi Johansen+ (retired 21 March 2006) 36,794 — — 18,297 18,497 nil 02 May 05 01 May 09

49,833 — — — 49,833 nil 10 May 06 09 May 10

79,662 — — — 79,662 nil 27 May 07 26 May 11

— 63,356 — — 63,356 nil 26 May 08 25 May 12

166,289 63,356 — 18,297 211,348

# During the year, the performance period for the awards granted under the Long Term Incentive Plan on 2 May 2002 ended and, on the basis of the company’s total shareholder return, 49.73% of shares under awards vested. These awards became exercisable either immediately or at any other time until the seventh anniversary of grant. The market price of ScottishPower ordinary shares at the date of grant of these awards was 409.29 pence and on 2 May 2005, being the date of vesting, was 422.75 pence. Long Term Incentive Plan awards granted before 2001 became exercisable on the fourth anniversary of grant. Awards granted in 2001 and subsequently became exercisable on the third anniversary of grant, as approved by shareholders.

Awards granted during the year were granted for no consideration. The market value of ScottishPower shares at the date of grant for Simon Lowth, Ian Russell, Charles Berry, David Nish and Judi Johansen was 469.75 pence and for Philip Bowman was 577.0 pence.

+ In accordance with the rules of the Plan the entitlements for these retired directors will be subject to pro-rating in respect of their period of service as a proportion of the performance period.

66 ScottishPower Annual Report & Accounts 2005/06

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TABLE 36

Directors’ interests in performance and other share plans at 31 March 2006 continued

Executive Share Option Plan 2001

Simon Lowth 220,937 — — — 220,937 389.3 27 May 07 27 May 14

220,937 — — — 220,937

Ian Russell† (retired 16 February 2006) 227,743 — — — 227,743 483.0 21 Aug 04 21 Aug 11

270,935 — — — 270,935 406.0 02 May 05 02 May 12

345,514 — — — 345,514 376.3 10 May 06 10 May 13

362,235 — — — 362,235 389.3 27 May 07 27 May 14

1,206,427 — — — 1,206,427

Charles Berry† (retired 6 September 2005) 107,660 — — — 107,660 483.0 21 Aug 04 21 Aug 11

147,783 — — — 147,783 406.0 02 May 05 02 May 12

167,441 — — — 167,441 376.3 10 May 06 10 May 13

205,523 — — — 205,523 389.3 27 May 07 27 May 14

628,407 — — — 628,407

David Nish† (retired 6 September 2005) 124,223 — — — 124,223 483.0 21 Aug 04 21 Aug 11

172,413 — — — 172,413 406.0 02 May 05 02 May 12

220,598 — — — 220,598 376.3 10 May 06 10 May 13

220,937 — — — 220,937 389.3 27 May 07 27 May 14

738,171 — — — 738,171

Judi Johansen† (retired 21 March 2006) 61,824 — 61,824 — — 339.1 10 Aug 05 501.2* 02 May 05 02 May 12

61,828 — 61,828 — — 339.1 10 Aug 05 501.2* 02 May 05 02 May 12

81,968 — 81,968 — — 351.4 10 Aug 05 501.2* 10 May 05 10 May 13

81,968 — — — 81,968 351.4 10 May 06 10 May 13

208,912 — — — 208,912 413.6 27 May 07 27 May 14

496,500 — 205,620 — 290,880

Sharesave Scheme

Simon Lowth — 3,534 — — 3,534 374.0 01 Sept 10 28 Feb 11

— 3,534 — — 3,534

Ian Russell (retired 16 February 2006) 5,290 — — — 5,290 301.0 01 Sep 08 28 Feb 09

5,290 — — — 5,290

Charles Berry (retired 6 September 2005) 2,941 — 2,941 — — 323.0** 01 Sep 05 512.0 01 Sep 05 28 Feb 06

— 2,533 — — 2,533 374.0** 01 Sep 08 28 Feb 09

2,941 2,533 2,941 — 2,533

David Nish (retired 6 September 2005) — 2,533 — — 2,533 374.0** 01 Sep 08 28 Feb 09

— 2,533 — — 2,533

* The exercise of Executive Share Option Plan 2001 options by Judi Johansen on 10 August 2005 was over 30,913 ADSs at US$23.55 per ADS and 20,492 ADSs at US$24.40 per ADS. On 10 August 2005 the market value of a ScottishPower ADS was US$29.51.

** Denotes options granted under a three-year scheme.

† In accordance with the rules of the Executive Share Option Plan 2001 the options of these retired directors are exercisable on or before the later of (i) 12 months after the date of retirement and (ii) 42 months after the date of grant.

(i) The market price of the shares at 31 March 2006 was 582.0 pence and the range during 2005/06 was 408.0 pence to 597.0 pence.

(ii) The Long Term Incentive Plan makes annual awards to acquire shares in ScottishPower at nil or nominal cost to the plan participants up to a maximum value equal to 75% of base salary. The award will vest only if the Remuneration Committee is satisfied that certain performance measures related to the sustained underlying financial performance of the company and sustained underlying performance in certain customer service standards 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 under awards granted before May 2001 was dependent upon how the company ranked 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 would vest depending upon the company’s ranking within each of the comparator groups. For awards granted in May 2001 and subsequently, the company’s total shareholder return performance is compared over a three-year period against an international comparator group of major energy companies. A percentage of the award vests dependent upon the company’s ranking within the comparator group. The plan participant may acquire the shares in respect of the percentage of the award which has vested at any time after the third (or fourth year for awards granted before 2001) up to the seventh year after the grant of the award. No dividends accrue to participants prior to vesting.

(iii) The company ceased granting under the Executive Share Option Plan 2001 to relevant executives and senior managers in 2004. The exercise of options granted to UK executives and senior managers, is subject to the performance criterion that the percentage increase in the company’s annualised earnings per share be at least 3% (adjusted for any increase in the Retail Price Index). This criterion is assessed at the end of the third financial year, the first year being the financial year starting immediately before the date of grant. If the criterion is not satisfied over this period, it is tested again at the end of the fourth financial year. If the criterion is not satisfied over this period, it is tested again at the end of the fifth financial year. If the criterion is not satisfied over this period, then the options lapse. The exercise of options granted to US participants is not normally subject to the satisfaction of performance criteria, and they normally become exercisable as follows: one-third of the options from the first anniversary of the date of grant, a further one-third from the second anniversary and the final one-third from the third anniversary of the date of grant. In 2002, an additional, conditional share option award was made to some senior managers, including Judi Johansen, under the Executive Share Option Plan 2001. The exercise of these additional, conditional options is subject to the same exercise period and performance criterion as options granted to UK participants.

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Remuneration Report of the Directors

(iv) Options granted to Judi Johansen under the PacifiCorp Stock Incentive Plan and the Executive Share Option Plan 2001 are granted over ScottishPower ADSs.

For the purposes of the above table, these options, in the case of Judi Johansen, have been converted to ordinary shares as follows: one ScottishPower ADS equals

four ScottishPower ordinary shares. The US$ADS option prices were converted so that they may be represented in terms of ScottishPower ordinary shares.

The prices were further converted at the closing exchange rate on 31 March 2006 of £1 = $1.736 so as to be quoted in pence in the above table.

(v) 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.

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 either three or five years under an Inland Revenue approved savings contract, subject to a current maximum.

(vi) Total gains made on exercise of directors’ share options and awards during the year were £328,786 (2005: £623,361). The conversion rate for gains made

by Judi Johansen is £1 = $1.785, being the average exchange rate during the year.

Approved by the Board and signed on its behalf by

NOLAN KARRAS Chairman of the Remuneration Committee

24 May 2006

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Safe Harbor Statement

Cautionary Statement for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995

Some statements contained herein may include statements regarding our assumptions, projections, expectations or beliefs about future events.

These statements are intended as “Forward-Looking Statements” within the meaning of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. All statements with respect to us, our corporate plans, future financial condition, future results of operations, future business plans, strategies, objectives and beliefs and other statements that are not historical facts are forward-looking. Statements containing the words “may”, “will”, “expect”, “anticipate”, “believe”, “intend”, “estimate”, “continue”, “plan”, “project”, “target”, “on track to”, “strategy”, “aim”, “seek”, “will meet” or other similar words are also forward-looking. These statements are based on our management’s assumptions and beliefs in light of the information available to us. These assumptions involve risks and uncertainties which may cause the actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements.

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. Important factors that are beyond ScottishPower’s ability to control or estimate precisely, and that may cause results to differ from expectations include, for example:

DIRECTORS’ RESPONSIBILITY FOR THE ACCOUNTS

The directors are responsible for preparing the Annual Report and the group Accounts in accordance with applicable law and International Financial Reporting Standards (“IFRSs”) as adopted by the European Union, and for preparing the parent company Accounts and the Remuneration Report of the Directors in accordance with applicable law and United Kingdom Accounting Standards (United Kingdom Generally Accepted Accounting Practice).

The directors are responsible for preparing Accounts for each financial year which give a true and fair view, in accordance with IFRSs, of the state of affairs of the group and of the profit or loss of the group and a true and fair view, in accordance with United Kingdom Generally Accepted Accounting Practice, of the state of affairs of the company for that period. In preparing those Accounts, the directors are required to:

select suitable accounting policies and then apply them consistently;

make judgements and estimates that are reasonable and prudent;

state whether the group Accounts comply with IFRSs, and with regard to the parent company Accounts whether applicable accounting standards have been followed, subject to any material departures disclosed and explained in the Accounts; and

prepare the Accounts on the going concern basis unless it is inappropriate to presume that the group will continue in business.

The directors are responsible for keeping proper accounting records that disclose with reasonable accuracy at any time the financial position of the company and the group and to enable them to ensure that the group Accounts comply with the Companies Act 1985 and Article 4 of the IAS Regulation and the parent company Accounts and the Remuneration Report of the Directors comply with the Companies Act 1985. They are also responsible for safeguarding the assets of the company and the group and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities.

Each of the directors in office as at the date of this Annual Report confirms that:

so far as he or she is aware, there is no relevant audit information of which the company’s auditors are unaware; and

he or she has taken all the steps that he or she ought to have taken as a director in order to make himself or herself aware of any relevant audit information and to establish that the company’s auditors are aware of that information.

AUDITORS

During the year, the company carried out a competitive tender in relation to the provision of audit services. Following the outcome of this exercise the Board, on the recommendation of the Audit Committee, will ask shareholders at the Annual General Meeting to appoint Deloitte & Touche LLP in place of the retiring auditors, PricewaterhouseCoopers LLP.

REPORT OF THE DIRECTORS

The Report of the Directors, comprising the statements and reports on pages 2 to 69 of this Annual Report & Accounts, has been approved by the Board and signed on its behalf by SHEELAGH DUFFIELD Secretary 24 May 2006 the success of reorganizational and cost-saving or other strategic efforts;

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;

the outcome of other proceedings conducted by regulatory commissions;

the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings;

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 fuel at favorable prices;

weather and weather-related impacts affecting demand for electricity and gas;

the availability of operational capacity of plants;

adequacy and accuracy of load and price forecasts that could impact the hedging strategy and costs to balance electricity load and supply;

unanticipated construction delays, changes in costs, receipt of required permits and authorizations, and other factors that could affect future generation plants and infrastructure additions;

the impact of interest rates and investment performance on pension and post-retirement expense;

the impact of new accounting pronouncements on results of operations; and

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

Other risk factors are detailed in Section 9.3.2 of the ‘Business Review’.

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Accounts 2005/06

Accounting Policies and Definitions 70

Critical Accounting Judgements and Key Sources of Estimation Uncertainty 81

Group Income Statement 84

Group Statement of Recognised Income and Expense 85

Group Cash Flow Statement 86

Movement in Net Cash and Cash Equivalents 87

Reconciliation of Movement in Net Cash and Cash Equivalents to Movement in Net Debt 87

Group Balance Sheet 88

Notes to the Group Accounts 89

Principal Subsidiaries and Other Investments 155

Independent Auditors’ Report on the Group Accounts 156

Selected Financial Data 157

Glossary of Financial Terms and US Equivalents 160

Company Balance Sheet 161

Company Statement of Total Recognised Gains and Losses 162

Company Reconciliation of Movement in Shareholders’ Funds 162

Notes to the Company Balance Sheet 163

Independent Auditors’ Report on the Company Accounts 167

Accounting Policies and Definitions

DEFINITIONS

BUSINESS SEGMENT DEFINITIONS

ScottishPower defines business segments for management reporting purposes based on a combination of factors, principally differences in products and services and the regulatory environment in which the businesses operate. Business segments have been included under either ‘continuing operations’ or ‘discontinued operations’ as appropriate.

The business segments of the group are defined as follows:

CONTINUING OPERATIONS UNITED KINGDOM

ENERGY NETWORKS (FORMERLY INFRASTRUCTURE DIVISION)

The transmission and distribution businesses within the group’s authorised area of Scotland and the distribution business of Manweb operating in Merseyside and North Wales.

ENERGY RETAIL & WHOLESALE (FORMERLY UK DIVISION)

The generation of electricity from the group’s own power stations, the purchase of external supplies of coal and gas for the generation of electricity, the purchase of external supplies of electricity and gas for sale to customers together with related billing and collection activities, gas storage, the sale of gas to industrial and domestic customers, and the sale of electricity to market participants in Scotland and England & Wales, and full participation in the British Electricity Trading and Transmission Arrangements (“BETTA”). BETTA replaced the New Electricity Trading Arrangements (“NETA”) in England & Wales with effect from 1 April 2005.

UNITED STATES

PPM ENERGY The competitive energy development, origination and marketing business serving wholesale customers in North American markets. Electricity products and services are provided from gas generation and renewable wind generation resources located across the US. Natural gas storage and hub services are provided from gas storage facilities located in Texas, New Mexico and Alberta, Canada.

OTHER

UNALLOCATED For the purposes of segmental analysis this comprises corporate office costs and the revenue and costs of the non-regulated businesses, previously included within the PacifiCorp segment, which were not included in the sale of PacifiCorp.

DISCONTINUED OPERATIONS UNITED STATES

PACIFICORP A vertically-integrated electric utility, disposed of on 21 March 2006, that included the generation, transmission and distribution and sale of electricity to retail, industrial and commercial customers in portions of six western states: Utah, Oregon, Wyoming, Washington, Idaho and California. The

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operations also included wholesale sales and power purchase transactions with various entities. The state regulatory commissions and Federal Energy Regulatory Commission (“FERC”) regulated the retail and wholesale operations. The subsidiaries of PacifiCorp supported its electric utility operations by providing coal mining facilities and services and environmental remediation.

REVENUE COST DEFINITIONS

COST OF SALES The direct costs of the generation and purchase of electricity and the purchase and transportation of natural gas.

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.

ADMINISTRATIVE EXPENSES The indirect costs of the businesses, the costs of corporate services and property rates.

OTHER DEFINITIONS

COMPANY OR SCOTTISHPOWER Scottish Power plc.

GROUP Scottish Power plc and its consolidated subsidiaries.

ASSOCIATES Entities in which the group holds a long-term interest and over which the group has significant influence.

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

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

GROUP ACCOUNTING POLICIES

The principal accounting policies applied in preparing the group’s consolidated Accounts are set out below. These are arranged to broadly follow the captions as they appear in the Group Income Statement and Group Balance Sheet. The principal accounting policies comprise the following:

A. Basis of accounting B. Basis of consolidation C. Goodwill D. Foreign currencies E. Revenue F. Operating profit G. Taxation

H. Intangible assets (excluding goodwill) I. Property, plant and equipment J. Cash and cash equivalents K. Borrowing costs

L. Impairment of property, plant and equipment and intangible assets (excluding goodwill)

M. Mine reclamation and closure costs N. Decommissioning costs O. Leased assets P. Risk and financial instruments

Q. Financial instruments (policies applied in the comparative figures for the year ended 31 March 2005) R. Inventories S. Grants and contributions T. Pensions and other post-retirement benefits U. Share-based payment V. Environmental liabilities W. Exchange rates

A. BASIS OF ACCOUNTING

The Accounts have been prepared for the first time in accordance with International Accounting Standards (“IAS”), International Financial Reporting Standards (“IFRS”) and International Financial Reporting Interpretations Committee (“IFRIC”) interpretations as adopted by the EU as required by Regulation (EC) No. 1606/2002 of the European Parliament and those parts of the Companies Act 1985 applicable to companies reporting under IFRS. In previous years, the Accounts were prepared in compliance with UK Generally Accepted Accounting Practice (“UK GAAP”) and the Companies Act 1985. This has resulted in certain changes to previously applied accounting policies. The effect of these changes in accounting policies are explained in the disclosures concerning the transition from UK GAAP to IFRS required by IFRS 1 ‘First-time Adoption of International Financial Reporting Standards’ set out in Note 42 to the Accounts.

As permitted by IFRS 1, the standards relating to financial instruments, IAS 32 ‘Financial Instruments: Disclosure and Presentation’ and IAS 39 ‘Financial Instruments: Recognition and Measurement’ have been applied with effect from 1 April 2005. Implementation of IAS 39 resulted in an increase in equity attributable to equity holders of Scottish Power plc of £281.4 million. The group has continued to use its previous UK GAAP accounting policies, as amended by IAS 21 ‘The Effects of Changes in Foreign Exchange Rates’ for financial instruments, as set out in accounting policy ‘Q. Financial instruments’ below, in preparing the IFRS financial information for the year ended 31 March 2005.

The format of the Group Income Statement has been prepared in accordance with the requirements of IAS 1 and reflects the impact of the adoption of IAS 32 and IAS 39 with effect from 1 April 2005.

Items which are included in operating profit are classified as exceptional where the directors consider that by virtue of their nature, size or incidence it is necessary for them to be displayed as a separate line item or separately within a line item if the financial statements are to be properly understood.

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Accounts 2005/06

In order to provide readers with a clear, consistent and more useful presentation of the group’s underlying performance, profit/(loss) for the financial year has been analysed between (i) profit before exceptional items and certain remeasurements and (ii) the effect of exceptional items and certain remeasurements.

Included in this latter category are:

– items which are included in operating profit but classified as exceptional as the directors consider that by virtue of their nature, size or incidence, it is necessary for them to be displayed as a separate line item or separately within a line item if the financial statements are to be properly understood. – fair value gains and losses on operating derivatives and financing derivatives including, for 2004/05 only, the impact on results of contracts which were previously fair valued but which are now subject to IAS 39. All of the group’s treasury activities and all but an immaterial proportion of the group’s energy management activities are undertaken with a view to economically hedging the group’s physical and financial exposures. A number of these contracts do not qualify for own use or hedge accounting under IAS 39 and are therefore fair valued through the Group Income Statement. In addition, those contracts which do qualify for cash flow hedge accounting can have an element of hedge ineffectiveness which is recorded in the income statement. The directors consider that this accounting treatment of fair valuing economic hedges and the resulting income statement volatility does not appropriately reflect the business purpose of these contracts. In order to provide a more meaningful presentation, the fair value movements on these contracts have been separated from all other aspects of the impact of IAS 39 which remain within underlying business performance. The fair value movements on such contracts to the extent they relate to operating activities are shown separately in the line item ‘Fair value gains on operating derivatives’ and, to the extent they relate to financing derivatives in the line item ‘Fair value losses on financing derivatives’.

– the reversal of the depreciation charge for PacifiCorp for the period from 24 May 2005, when it became a discontinued operation, until its date of disposal, as required by IFRS 5 ‘Non-current Assets Held for Sale and Discontinued Operations’.

– the taxation effect of the above items.

Further analysis of the items included in the column Exceptional items and certain remeasurements is provided in Note 2 to the Accounts.

This income statement format aligns with the group’s calculations of adjusted earnings per share which were previously presented in the group’s quarterly Accounts in 2005/06.

B. BASIS OF CONSOLIDATION

The group Accounts incorporate the Accounts of the company and its subsidiaries to 31 March each year. Subsidiaries are those entities over which the group has the power to govern the financial and operating policies, generally accompanying a shareholding that confers more than half of the voting rights. 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. The group Accounts also include the group’s share of results and net assets of associates and jointly controlled entities.

On acquisition, the assets and liabilities of a subsidiary are measured at their fair values at the date of acquisition. The cost of an acquisition is measured at the fair value of any assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange, plus costs directly attributable to the acquisition. Any excess of the cost of acquisition over the fair values

of the identifiable net assets acquired is recognised as goodwill. The interest of minority shareholders is initially stated at the minority’s proportion of the fair values of the assets and liabilities recognised. In accordance with the exemption permitted by IFRS 1, business combinations accounted for prior to the group’s date of transition to IFRS on 1 April 2004 have not been restated to comply with IFRS 3 ‘Business Combinations’.

The results of subsidiaries acquired or disposed of during the year are included in the income statement from the effective date of acquisition or up to the effective date of disposal, as appropriate.

The group Accounts include the group’s share of the post-tax results and net assets of associates and jointly controlled entities using the equity method of accounting. Associates are those entities over which the group has significant influence, but not control, generally accompanying a shareholding that confers between 20% to 50% of the voting rights. Jointly controlled entities are those entities over which the group has joint control with one or more external parties and over which there has to be unanimous consent by all parties to the strategic, financial and operating decisions.

On acquisition of all or part of a minority interest in a subsidiary, the assets and liabilities being acquired are measured at book value at the date of acquisition. The excess of the fair value of the purchase consideration over the book value of the assets acquired is recorded as goodwill. The results of the subsidiary relating to the minority interest for the period up until the date of acquisition are included in the income statement as amounts attributable to minority interests.

As a result of the group’s decision to sell PacifiCorp, PacifiCorp has been treated as a disposal group held for sale and a discontinued operation in accordance with IFRS 5. As a consequence of the classification as a discontinued operation, the net profit of PacifiCorp has been shown in a single line ‘Profit/(loss) for the year from discontinued operations’, in the income statement.

The results of discontinued operations include the UK/US interest rate differential benefit, the loss following de-designation

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of net investment hedges arising from the group’s US dollar hedging programme relating to PacifiCorp’s net assets and the impact of the US dollar earnings hedges relating to the results of PacifiCorp. This programme terminated following completion of the sale of PacifiCorp.

C. GOODWILL

Goodwill represents the excess of the fair value of the purchase consideration over the group’s share of the fair value of the identifiable assets and liabilities of an acquired subsidiary, associate, jointly controlled entity or business at the date of acquisition.

Goodwill is recognised as an asset and reviewed for impairment at least annually and whenever there is an indication of impairment. Goodwill is carried at cost less amortisation charged prior to the group’s transition to IFRS on 1 April 2004 less accumulated impairment losses. Any impairment is recognised in the period in which it is identified.

On disposal of a subsidiary, associate, jointly controlled entity or business, the attributable amount of goodwill is included in the determination of the profit or loss on disposal.

Goodwill arising on acquisitions after 31 March 1998 but prior to the group’s date of transition to IFRS, 1 April 2004, has been retained as an asset at the previous UK GAAP amounts as at that date. As required by IFRS 1, this goodwill was reviewed for impairment as at the date of transition to IFRS.

Goodwill arising on acquisitions prior to 1 April 1998 was written off against reserves. It has not been reinstated as an asset on transition to IFRS as permitted by IFRS 1 and will not be included in determining any subsequent profit or loss on disposal. Further details of goodwill written off to reserves are set out in Note 33 to the Accounts.

D. FOREIGN CURRENCIES

Transactions undertaken by each of the group’s entities are measured using the currency of the primary economic environment in which the entity operates (functional currency) and foreign currency items are translated into the functional currency at the spot rate at the date of the transaction. The group’s consolidated Accounts are presented in sterling, which is the group’s presentational currency.

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 operations and foreign currency borrowings and changes in fair value of derivatives to the extent that they are effective net investment hedges are taken directly to the group’s translation reserve and are shown in the statement of recognised income and expense. Upon disposal of the related operation, such translation differences are recognised as income or as expense in the period of disposal.

Cumulative translation differences in respect of the period prior to the group’s date of transition to IFRS, 1 April 2004, have been transferred to the translation reserve, as required by IAS 21. These amounts will be included in the determination of any future gain or loss on disposal of the related operations.

Goodwill and fair value adjustments arising on the acquisition of a foreign entity are treated as assets and liabilities of the foreign entity and translated at the closing rate of exchange.

E. REVENUE

Revenue comprises the contracted sales value of energy, goods and other services supplied to customers during the year and excludes Value Added Tax and intra-group sales. Revenue from

the sale of energy 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, based on external data supplied by the electricity and gas market settlement processes.

F. OPERATING PROFIT

The group’s share of the post-tax results of associates and jointly controlled entities is included within operating profit as the operations are closely related to those of the parent and other subsidiaries.

G. TAXATION

The group’s liability for current tax is calculated using the tax rates that have been enacted or substantially enacted by the balance sheet date.

Deferred tax is the tax expected to be payable or recoverable on the difference between the carrying amounts of assets and liabilities in the balance sheet and the corresponding tax bases used in the computation of taxable profits (temporary differences), and is accounted for using the balance sheet liability method. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profit will be available against which deductible temporary differences can be utilised.

Deferred tax is calculated at the tax rates that are expected to apply in the period in which the liability is settled or the asset is realised, on a non-discounted basis, and is charged in the income statement, except where it relates to items charged or credited to equity (via the statement of recognised income and expense), in which case the deferred tax is also dealt with in equity and is shown in the statement of recognised income and expense.

H. INTANGIBLE ASSETS (EXCLUDING GOODWILL) H1. COMPUTER SOFTWARE COSTS

The costs of acquired computer software are capitalised on the basis of the costs incurred to acquire and bring to use the specific software and are amortised on a straight-line basis over their operational lives. Costs directly associated with the development of computer software programmes that will probably generate economic benefits over a period in excess of

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Accounts 2005/06 one year are capitalised and amortised over their estimated operational lives. Costs include employee costs relating to software development and an appropriate proportion of relevant overheads directly attributable to bringing the software into use.

H2. HYDRO RELICENSING COSTS

Costs relating to the relicensing of the group’s hydroelectric plants were capitalised and amortised, generally on a straight-line basis, over the period of the licence. This policy applied to PacifiCorp, the group’s former regulated US business.

H3. EMISSIONS ALLOWANCES

The group participates in the EU Emissions Trading Scheme. Purchased emissions allowances are initially recognised at cost (purchase price) within intangible assets. Allocated allowances awarded to the group by the government or a similar body are recorded at nominal value (nil value). The group recognises liabilities in respect of its obligations to deliver emissions allowances to the extent that the allowances to be delivered exceed allocated allowances. Any liabilities recognised are measured based on the cost of allowances purchased up to the level of purchased allowances held and thereafter at the market price of allowances at the balance sheet date.

The allowances held within intangible assets may be surrendered at the end of each compliance period reflecting the consumption of economic benefit. As a result no amortisation is recorded during the period.

The main amortisation periods used by the group are set out below.

Years

Computer

software costs 3 – 10

Hydro

relicensing costs (in respect of PacifiCorp) 25

I. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is stated at cost and is generally depreciated on the straight-line method over the estimated operational lives of the assets. Property, plant and equipment includes capitalised employee, interest and other costs that are directly attributable to the construction of fixed assets. Reviews are undertaken annually of the estimated remaining lives and residual values of property, plant and equipment. Residual values are assessed based on prices prevailing at each balance sheet date.

Land is not depreciated except in the case of mines as set out in accounting policy ‘M. Mine reclamation and closure costs’ 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

Repairs and maintenance costs are expensed during the period in which they are incurred.

J. CASH AND CASH EQUIVALENTS

Cash and cash equivalents comprise cash on hand, available-for-sale financial assets, held-to-maturity investments to the extent that they are realisable within 90 days and bank overdrafts that are repayable on demand the next business day.

K. BORROWING COSTS

Borrowing costs directly attributable to the acquisition, construction or production of major qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use.

L. IMPAIRMENT OF PROPERTY, PLANT AND EQUIPMENT AND INTANGIBLE ASSETS (EXCLUDING GOODWILL)

At each balance sheet date, the group reviews the carrying amount of its property, plant and equipment and intangible assets to determine whether there is any indication that those assets have suffered an impairment loss. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment loss (if any). Where the asset does not generate cash flows that are independent from other assets, the group estimates the recoverable amount of the cash generating unit to which the asset belongs.

M. MINE RECLAMATION AND CLOSURE COSTS

Provision was made for mine reclamation and closure costs when an obligation arose out of events prior to the balance sheet date. The amount recognised was the present value of the estimated future expenditure determined in accordance with local conditions and requirements. A corresponding asset was also created of an amount equal to the provision. This asset, together with the cost of the mine, was subsequently depreciated on a unit of production basis. The unwinding of the discount was included within finance costs. This policy applied to PacifiCorp, the group’s former regulated US business.

N. DECOMMISSIONING COSTS

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

O. LEASED ASSETS

O1. THE GROUP AS LESSEE

Assets leased under finance leases, where substantially all the risks and rewards of ownership are transferred to the group, are capitalised and depreciated over the shorter of the lease periods and the estimated operational lives of the assets. The corresponding liability is included in the balance sheet as a finance lease obligation. Lease payments are apportioned between finance charges and reduction of the lease obligations so as to achieve a constant rate of interest on the remaining balance of the liability. Finance charges are charged directly

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against income, unless they are directly attributable to qualifying assets, in which case they are capitalised in accordance with the group’s accounting policy on ‘K Borrowing costs’. Rentals payable under operating leases are charged to the income statement on a straight-line basis over the period of the lease.

O2. THE GROUP AS LESSOR

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

P. RISK AND FINANCIAL INSTRUMENTS

P1. IMPLEMENTATION OF IAS 32 AND IAS 39

The group has adopted IAS 32 and IAS 39 in the financial year ended 31 March 2006. The EU adopted a regulation in November 2004 (as amended in November 2005) endorsing IAS 39 with the exception of certain provisions relating to hedge accounting. The group has applied the EU-adopted standard in preparing these Accounts. Applying the full version of the standard as opposed to the EU-adopted standard would have had no impact on the group’s financial statements. In accordance with the transitional arrangements set out in those standards, the group has not restated the prior year’s comparative figures to show the effect of IAS 32 and IAS 39. For the year ended 31 March 2005, financial instruments were accounted for in accordance with the group’s previous policies for financial instruments under UK GAAP as set out below under the heading ‘Q. Financial instruments (policies applied in the comparative figures relating to the year ended 31 March 2005)’. The effects of the implementation of IAS 32 and IAS 39 on 1 April 2005 are set out in Note 43 to the Accounts.

IAS 39 requires that certain financial assets be measured at fair value in the balance sheet with changes in fair value reported through either the income statement or for available-for-sale financial assets, through reserves. Exceptions apply to assets classified as loans and receivables and held-to-maturity investments, which are measured at amortised cost using the effective interest method.

With respect to financial liabilities, IAS 39 prescribes measurement at amortised cost using the effective interest method.

Derivative instruments are carried at fair value with special rules applying to all financial instruments which form part of a hedging relationship.

Commodity purchases and sales that do not qualify for the own use exemption are also measured at fair value through the income statement, or through reserves where cash flow hedge accounting is achieved.

Embedded derivatives in other financial instruments or other host contracts are treated as separate derivatives when their risks and characteristics are not closely related to those of the host contracts and the host contracts are not carried at fair value. Unrealised gains or losses on remeasurement of embedded derivatives are reported in the income statement as part of ‘fair value gains on operating derivatives’ and ‘fair value losses on financing derivatives’.

IAS 32 prescribes certain disclosures on the use and impact of financial instruments designed to help the users of the Accounts understand the significance of the financial instruments to an entity’s financial position, performance and cash flows, as well as factors that affect amounts, timing and risks associated with future cash flows.

P2. RISK CONTROL ENVIRONMENT

The risk policy developed by the Board is supported by a governance structure, which includes the Executive Team (“ET”), a Business Risk and Investment Committee (“BRIC”) for each business, Business Risk Assessment Teams and the independent Group Risk Management function.

The structure ensures that the risk management procedures established for each business to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in its business are adequately designed and implemented and that an effective and efficient system of internal controls is maintained. The businesses adhere to their specific business risk limits and guidelines which are endorsed by the BRIC and approved by the ET. These limits are consistent with the allocation of group risk capital to the businesses. The business limits are allocated based upon the group’s total risk capital, being the capital that would cover acceptable potential losses resulting from market and credit risks. The Board has allocated a certain amount of risk capital, based on a 99% confidence interval over a two year period. This risk capital amount is calculated as the maximum sustainable loss over a two year period such that the group’s financial ratios would still warrant an investment grade rating from rating agencies such as Standard & Poor’s or Moody’s.

The risks faced by the group fall into the following categories: market risk (both energy price and energy volumetric risk), operational risk, credit risk, insurance risk, interest rate risk, inflation risk, foreign exchange risk, liquidity risk, derivative risk, administrative risk, legal risk, regulatory risk, political risk, security risk, pension risk and risks relating to the availability of generation, adequate fuel supply and transportation.

The Board’s position on risk and strategy for risk management are contained in the group Energy Management and Risk Management Policy. The Board implements its policies through a rigid risk governance structure, whereby responsibilities

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Accounts 2005/06 are vested with groups, committees and individuals on a global as well as business level. Further details on the group’s risk policy are given in the individual risk sections below.

Generally, the risk management policy and control environment ensures that transactions undertaken and instruments used fall into the types of transactions approved by the Board and are properly validated within the authorised levels of authority. Transactions include instruments such as physically-settled instruments, financially-settled instruments, other contractual obligations, regulatory requirements, and other obligations. The types of instruments which can be used are approved for each business. Subject to the limits requirements discussed above, no transaction is executed unless it is an instrument approved by the BRIC. Further information on the value of derivative instruments utilised by the group is disclosed in Note 25 to these Accounts. Authorised personnel are permitted to engage only in those activities specified in the business operational policies and procedures.

A clear reporting structure has been implemented within the group. It ensures that the portfolios are monitored on a timely basis and sufficient information is made available to management to enable quick response of the business to the dynamic characteristics of its market environment. Those reports include daily position, mark-to-market (“MtM”), Value at Risk (“VaR”) reports as well as periodical fundamentals reports, stress and scenario reports, credit watch, credit exposure, accounting and insurance reports.

The group’s exposure and risk management and control activities in the areas with greater significance to the Accounts are reviewed in greater detail below.

P2.1 ENERGY MANAGEMENT

The group’s risk policy relating to energy management is designed to ensure that the energy management and risk management (“EMRM”) activities are consistent with the level of risk tolerance acknowledged by the Board and that a risk control and management framework is established and maintained to monitor and measure risks in existing portfolios of assets and contracts, to develop and define appropriate strategies and transactions to manage those risks and to approve and authorise new transactions and energy instruments. The policy is reviewed at least on an annual basis to ensure that its relevance to the current environment is maintained.

Each business of the group that engages in energy management activities establishes a set of operational policies and procedures incorporating the policies and principles set out in the group Energy Management and Risk Management Policy and provides detailed information with respect to the roles and responsibilities of each function involved in EMRM activities. These operational policies and procedures are presented to the BRIC for approval at least annually.

The key risk control activities implemented by each business to address the energy management and risk management objectives of the group are:

Market risk

ongoing basis, including changes to assumptions and model inputs. Changes that can have significant impact on the Accounts require additional review and approval by the BRIC, ET or Board, as appropriate.

The group utilises hedging instruments in accordance with the approved risk strategies designed to keep exposure within the risk limits discussed above.

Operational risk

Operational risk is associated with generation, including management of physical fuel supply for the former US mining operations, transmission and distribution and other key system assets subject to service or supply interruptions. It is measured through the impact of system failures on the fair value of contracts at market prices. This risk is controlled through insurance, maintenance and prudent operations practices.

Credit risk

At the counterparty level the group employs specific eligibility criteria in determining appropriate limits for each prospective counterparty and supplements this with netting and collateral agreements including margining, guarantees, letters of credit and cash deposits where appropriate. Counterparty exposures are then monitored on a daily basis.

Insurance risk

Where cost effective, the group maintains a wide-ranging insurance programme providing financial protection, predominately against catastrophic risks. The insurance market has continued to show mixed trends in pricing over the past year. For property insurance, there has been a general increase in premiums due to the effects of hurricanes and other natural disasters. Business interruption insurance has generally increased due to increased exposures arising from significantly higher commodity prices.

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Other classes of insurance have resulted in net reductions in premiums due to competition in the insurance market and a favourable loss history. The group has worked closely with its insurance advisors and insurers to maintain efficiencies and long-term stability in premium costs. The renewal of the group’s main insurance policies for 2006/07 has been completed with commercial insurers delivering a net premium reduction, albeit with the group taking on increased exposures for some classes. These increased exposures are not deemed to be significant.

P2.2 Treasury

The group’s risk policy within treasury and financing is designed to ensure that the group’s exposure to variability of cash flows and asset values due to fluctuations in the market interest and foreign exchange rates and inflation are minimised and managed within levels consistent with the Board’s risk appetite. All treasury transactions are undertaken to manage the risks arising from the group’s underlying economic activities and no speculative trading is undertaken. The day-to-day treasury activities are performed by the group’s treasury function. The latter reports to the Board on a regular basis through the monthly group Performance and Risk Report and is subject to internal audit.

Interest rate risk

The group is exposed to interest rate risk with respect to its assets and liabilities affected by changes in the market interest rates. The group manages its exposure to interest rate risk by maintaining a percentage of its debt at a fixed rate of interest. The long-term targeted benchmark is a mix of 70% fixed rate and 30% floating rate debt. The exposure is managed by either issuing fixed and floating rate debt in proportions consistent with the group’s appetite for risk, or by using a range of derivative financial instruments to create the desired fixed/floating mix.

Inflation risk

To manage inflation risk, arising from the fact that a portion of UK revenues are linked to inflation, the group maintains part of its debt portfolio in index-linked liabilities. This is done either through issuing such liabilities or through swapping fixed rate into index-linked debt. The group’s target index rate exposure is about 10% of the total liability portfolio.

Foreign exchange risk

The group’s foreign operations expose it to foreign exchange risk, both translation and transaction risk. Translation risk is associated with changes in the value of the group’s foreign assets due to movements in the underlying currency exchange rates. Transaction risk is seen as the risk of changes in the value of transactions and associated cash flows denominated in foreign currencies, due to changes in those currency exchange rates. The group aims to hedge a substantial proportion of its US net assets with dollar liabilities. The resulting stream of dollar interest on natural dollar debt therefore acts as a natural hedge to the translation of US profits.

In those cases where transaction risk arises as a result of imports of capital or other goods denominated in foreign currencies, the exposure is hedged as soon as it is committed.

Liquidity risk

In order to manage its liquidity risk and create financial efficiencies the group arranges that its 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 also utilises undrawn but committed revolving credit facilities.

Derivative risk

The use of derivative financial instruments (other than those described for energy commodities above) relates directly to underlying and anticipated indebtedness, foreign subsidiary net assets and business transactions denominated in foreign currencies.

P3. HEDGING ACTIVITIES

In order to manage the impact of financial risks to the group and report results consistent with the operational strategies, the Board has endorsed the use of derivative financial instruments as hedging tools. Those instruments include fixed and floating swaps (interest rate, cross currency and commodity agreements), swaptions, financial options, financial and commodity forward contracts, commodity futures, commodity options and other complex derivatives. Such physical and financially settled instruments are held by the group to match exposures and are not held for financial trading purposes. Exceptions exist in the group’s competitive businesses, Energy Retail & Wholesale and PPM Energy, where a limited and controlled number of transactions and derivatives may be held for proprietary trading purposes.

The group utilises derivative instruments to manage its exposure to the variability of future cash flows caused by risks associated with recognised assets or liabilities or transactions highly probable of occurring (cash flow hedging). In addition, the group utilises hedging strategies with respect to the exposure to changes in fair value of recognised assets and liabilities or unrecognised firm commitments (fair value hedging). Finally, hedging of net investments in foreign operations is undertaken with respect to the group’s US business PPM Energy.

Using regression analysis and comparative value changes, the group designates derivatives as hedging instruments when it is expected that there will be high correlation between the changes in fair value of the instrument and the changes in fair value of the hedged item. Such correlation needs to be within the limits of 80% to 125% for the hedge to be considered highly effective. The group assesses hedge effectiveness on at least a quarterly basis to establish whether the assumptions and application criteria for hedge accounting going forward continue to be supported. The group will discontinue hedge accounting from the time that a hedging relationship has ceased to be highly effective. Cash flow hedging designation is only undertaken for future transactions, which are and remain highly probable of occurring.

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Accounts 2005/06

When certain conditions are met, the group applies the following accounting rules prescribed by IAS 39 for hedging activities:

P3.1 CASH FLOW HEDGES

The portion of gain or loss of the hedging instrument that was determined to be an effective hedge is recognised directly in equity and forms part of the hedge reserve. The ineffective portion of the change in fair value of the hedging instruments is recognised in the income statement within ‘Fair value gains on operating derivatives’ for hedges of underlying operations. For hedges of financing activities, any ineffectiveness is recognised within ‘Fair value losses on financing derivatives’ in the income statement. If the cash flow hedge of a highly probable forecasted future transaction results in the recognition of a non-financial asset, the associated gains or losses on the derivative that had previously been recognised in equity are released to the income statement in line with consumption of the asset. For hedges that result in recognition of a financial asset or a liability, amounts deferred in equity are recognised in the income statement in the same period in which the hedged item affects the income statement.

P3.2 FAIR VALUE HEDGES

The gain or loss from remeasuring the hedging instrument at fair value is recognised directly in the income statement. The gain or loss on the hedged item adjusts the carrying amount of the hedged item (when the item would otherwise have been measured at amortised cost) and is recognised in the income statement. The group starts amortisation of any such adjustments to the carrying value of the hedged item when the hedging relationship ends.

P3.3 NET INVESTMENT HEDGES

The group hedges its net investments in its US operations. The risk hedged relates to a proportion of the foreign currency exposure of the group’s share of the businesses’ net assets. The proportion of the gain or loss of the hedging instrument that was determined to be an effective hedge is recognised directly in equity and forms part of the translation reserve. The ineffective portion of the change in fair value of the hedging instrument is recognised in the income statement within ‘Fair value losses on financing derivatives’. On disposal of the foreign investment, the gains or losses on the hedging instrument that related to the effective portion of the hedge that had previously been recognised in equity are recycled to the income statement.

P3.4 DISCONTINUING HEDGE ACCOUNTING

The group discontinues prospectively hedge accounting when the hedge instrument expires or is sold, terminated or exercised, when the hedge relationship no longer qualifies for hedge accounting or when the designation is revoked. In the case of cash flow hedging, any gain or loss that has been recognised in equity until that time remains separately recognised in equity until the forecast transaction occurs. If the transaction is no longer expected to occur, related cumulative gains and losses which have been previously deferred in equity are recognised in the income statement.

Changes in the fair value of derivative financial instruments that do not qualify for hedge accounting are recognised in the income statement within ‘Fair value losses on financing derivatives’ as they arise.

P4. FINANCIAL INSTRUMENTS

Financial liability and equity instruments are classified according to the substance of the contractual arrangements. They are valued as described in Note 23 Financial assets and Note 24

Financial liabilities. An equity instrument is any contract that evidences residual interest in the assets of the group after deducting all of its liabilities.

All financial assets (excluding derivatives) are accounted for using settlement date accounting.

P4.1. EQUITY INVESTMENTS

The Group Income Statement includes the group’s share of the post-tax results of associates and jointly controlled entities. The Group Balance Sheet includes the investment in associates and jointly controlled entities at the group’s share of their net assets.

Other investments include investments where the group holds less than 20% of an entity’s equity and does not exercise significant influence over the operating policies and strategic decisions of this entity. Such investments are initially measured at fair value. They are classified as either held for trading or available-for-sale and are measured at subsequent reporting dates, at fair value. The gains and losses from changes in fair value of available-for-sale equity investments are recognised directly in equity until the instrument is disposed of or determined to be impaired, at which point those cumulative gains and losses are included in the income statement for the period. Investments in equity instruments which do not have a quoted market price and whose value cannot be reliably measured are held at cost.

P4.2 DEBT INSTRUMENTS

The group measures all debt instruments, whether financial assets or financial liabilities, initially at fair value. This is taken to be the net transaction price paid or received. In cases where part of the consideration is for something other than the instrument itself, the group estimates the fair value of the instruments using a valuation technique whose inputs are made of observable market data, or based on the value of similar instruments traded at that time in observable markets.

Transaction costs (any such costs incremental to and directly attributable to the acquisition, issue or disposal of the financial instruments) are accounted for based on the classification of the instrument by the group. Namely, transaction costs for all instruments classified as ‘fair value through the income statement’ are recognised in the income statement immediately upon recognition. For financial instruments carried

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at amortised cost, transaction costs are included in the calculation of the effective interest rate and in effect are amortised to the income statement over the life of the asset.

The subsequent measurement of financial instruments follows their classification by the group. Financial instruments classified as ‘fair value through the income statement’ are remeasured to their fair value with gains and losses recognised in the income statement for the period. Available-for-sale financial assets are remeasured at fair value with gains and losses recorded in equity. Any related interest payments, impairment losses and foreign exchange gains and losses are recognised in the income statement in the period they occur. Other financial instruments, including loans and receivables and held-to-maturity investments are measured at amortised cost using the effective interest method.

P4.3 COMMODITY CONTRACTS

Commodity contracts entered into and held for the purpose of the group’s own purchase, sale or usage requirements are accounted for under the own use exemption in IAS 39. All commodity contracts, which do not qualify for the own use exemption, including those non-physical contracts, entered into for the purpose of trading, but excluding contracts designated in hedging relationships to which special rules apply, are recorded at fair value on the balance sheet with changes in fair value reflected through the income statement. Details on the accounting policies for hedging are disclosed in accounting policy ‘P3. Hedging activities’.

P4.4 TREASURY DERIVATIVES

The group uses a number of derivatives to manage exposure to interest rate and currency fluctuations and the related value of net investments in foreign operations. When designated as hedges such instruments are accounted for in accordance with the methods described in accounting policy ‘P3. Hedging activities’. Additionally, amounts payable/receivable under interest rate hedges are accounted for as adjustments to finance costs/finance income for the period. Any other derivative instruments, which are used for the purpose of economic hedging but have not been designated in hedging relationships in accordance with IAS 39, are held at fair value with changes from remeasurement recorded through the income statement within ‘Fair value losses on financing derivatives’.

Instruments designated in hedging relationships include interest rate swaps, forward currency contracts and cross currency interest rate swaps. The latter swaps allow the designation of one instrument to hedge more than one risk where fixed for floating cross currency swaps are used.

P5. VALUATION OF FINANCIAL INSTRUMENTS

The group’s valuation strategies for derivative and other financial instruments utilise as far as possible quoted prices in an active trading market.

appropriate point of delivery where a market price exists with appropriate adjustments for the actual point of delivery, including if applicable currency adjustments.

In the absence of quoted prices for identical or similar assets or liabilities, it is sometimes necessary to apply valuation techniques where contracts are marked to approved models. Models are used for developing both the forward curves and the valuation metrics of the instruments themselves where the instruments are complex combinations of standard or nonstandard products. All models are subject to rigorous testing prior to being approved for valuation and subsequent continuous testing and approval procedures designed to ensure the validity and accuracy of the model assumptions and inputs.

P6. COMPOUND INSTRUMENTS

The group accounts for its US dollar convertible bonds as US dollar liabilities with the foreign exchange and equity-linked embedded derivative components of the convertible bonds separately identified and measured at fair value through the income statement. At the date of issue the value of the liability component was estimated using the prevailing market interest rate for a similar non-convertible debt. The fair value of embedded derivatives is the difference between the market value

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Accounts 2005/06 of the convertible bonds and the fair value of similar non-convertible debt. Issue costs and the opening value of the embedded derivative are amortised through the income statement to bring the debt back to par value at maturity.

Prior to the implementation of IAS 39, the US dollar convertible bond was accounted for at amortised cost with no anticipation of equity conversion.

P7. OFFSETTING OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES

The group offsets a financial asset and a financial liability and reports the net amount only when the group has a legally enforceable right to set off the amounts and intends either to settle on a net basis, or to realise the asset and settle the liability simultaneously.

Q. FINANCIAL INSTRUMENTS (POLICIES APPLIED IN THE COMPARATIVE FIGURES FOR THE YEAR ENDED 31 MARCH 2005) Q1. DEBT INSTRUMENTS

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

Q2. INTEREST RATE SWAPS/FORWARD RATE AGREEMENTS

These are used to manage debt interest rate exposures. Amounts payable or receivable in respect of these agreements were recognised as adjustments to interest expense over the period of the contracts. Where associated debt was not retired in conjunction with the termination of an interest swap, gains and losses were deferred and were amortised to interest expense over the remaining life of the associated debt to the extent that such debt remained outstanding.

Q3. INTEREST RATE CAPS/SWAPTIONS/OPTIONS

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

Q4. CROSS CURRENCY INTEREST RATE SWAPS

These are used to hedge both foreign exchange and interest rate exposures arising on foreign currency debt and to hedge overseas net investment. Where used to hedge debt issues, the debt was recorded at the hedge contracted rate and the accounting was otherwise in accordance with interest rate swaps detailed above. Where used to hedge overseas net investments, spot gains or losses were recorded on the balance sheet and in the statement of total recognised income and expense, with interest recorded in the income statement.

Q5. 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 hedging forecast transactions were not accounted for until the maturity of the contract. Foreign currency receivables and payables that were hedged with forward contracts were translated at the contracted rate at the balance sheet date. Spot gains or losses on hedges of the overseas net investments were recorded on the balance sheet and in the statement of total recognised income and expense with the interest rate differential reflected in the income statement.

Q6. HYDROELECTRIC AND TEMPERATURE HEDGES

These instruments were used in PacifiCorp, the group’s former regulated US business, to hedge fluctuations in weather and temperature in the US. On a quarterly basis, the group estimated and recorded a gain or loss in the income statement corresponding to the total expected future cash flows from these contracts.

Q7. COMMODITY CONTRACTS

Where there was no physical delivery associated with commodity contracts, they were recorded at fair value on the balance sheet with movements reflected through the income statement. Gas and electricity future contracts are undertaken for hedging and proprietary trading purposes. Where the instrument was a hedge, the fair values were initially reflected on the balance sheet and subsequently reflected through the income statement to match the recognition of the hedged item. Where the instrument was for proprietary trading the fair values were reflected through the income statement.

R. INVENTORIES

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

S. GRANTS AND CONTRIBUTIONS

Capital grants and customer contributions in respect of additions to property, plant and equipment are treated as deferred income within non-current liabilities and released to the income statement over the estimated operational lives of the related assets.

T. PENSIONS AND OTHER POST-RETIREMENT BENEFITS

The group provides pensions through defined benefit schemes. The cost of providing benefits is determined using the projected unit credit method, with actuarial valuations being carried out at each balance sheet date. Actuarial gains and losses are recognised in full, directly in retained earnings, in the period in which they occur and are shown in the statement of recognised income and expense. The current service cost element of the pension charge is deducted in arriving at operating profit. The expected return on pension scheme assets and interest on

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pension scheme liabilities are included within finance income and finance costs. The retirement benefits obligation recognised in the balance sheet represents the net deficit in the group’s defined pension schemes together with the net deficit in the group’s other post-retirement benefit arrangements, principally healthcare benefits, which are accounted for on a similar basis to the group’s defined benefit pension schemes.

U. SHARE-BASED PAYMENT

IFRS 2 ‘Share-based Payment’ has been applied to all grants of equity instruments after 7 November 2002, in accordance with the transitional provisions of the standard. The group makes equity-settled share-based payments to certain employees under the terms of the group’s various employee share and share option schemes. Equity-settled share-based payments are measured at fair value at the date of grant and expensed on a straight-line basis over the vesting period, based on an estimate of the shares that will ultimately vest.

Fair value is measured by use of a Monte Carlo simulation method in respect of the group’s Long Term Incentive Plan and the binomial method for the group’s other share schemes. The expected lives used in the model have been adjusted for estimates of the effects of non-transferability, exercise restrictions and behavioural considerations.

Own shares held under trust for the group’s employee share schemes are deducted in arriving at shareholders’ equity. Purchases and sales of own shares are disclosed as changes in shareholders’ equity.

V. 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 finance costs.

W. EXCHANGE RATES

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

Year ended 31 March

2006

2005

Average

rate for quarters ended:

June $1.86/£ $1.81/£

September $1.79/£ $1.82/£

December $1.75/£ $1.87/£

March $1.75/£ $1.89/£

Closing

rate as at 31 March $1.74/£ $1.89/£

A glossary of terms used in the Accounts and their US equivalents is set out on page 160.

Critical Accounting Judgements and Key Sources of Estimation Uncertainty

IFRS

(i)

IFRS - FINANCIAL INSTRUMENTS

The group’s valuation strategies for derivative and other financial instruments are set out in accounting policy ‘P5. Valuation of financial instruments’.

The assumptions within the models used to value financial instruments are critical, since any changes in assumptions could have a significant impact on the fair values and movements which are reflected in the Group Income Statement and Group Balance Sheet. There is little formal guidance to assist in applying IAS 39 to non-treasury contracts. As a result, significant judgements must be made in applying IAS 39 to the group’s energy contracts in particular. Disclosures relating to the group’s derivative financial instruments are set out in Note 25 to the Accounts.

(ii) IFRS - REVENUE

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Accounts 2005/06 the year. At the end of each accounting period, amounts of energy delivered to customers since the last billing date are estimated and the corresponding unbilled revenue is estimated and recorded as sales. Unbilled revenues included within accrued income in the Group Balance Sheet relating to the group’s retail customers of continuing operations at 31 March 2006 amounted to £297 million (2005: £246 million).

(iii) IFRS – TAX

(iv) IFRS – IMPAIRMENT OF PROPERTY, PLANT AND EQUIPMENT

(v)

IFRS – PROVISIONS AND CONTINGENCIES

Contingent liabilities are required to be disclosed in the Notes to the Group Accounts, unless the possibility of a transfer of economic benefits is remote. Contingent gains are not recognised unless realisation of the profit is virtually certain. Appropriate disclosures of contingent liabilities are made regarding litigation, tax matters, and environmental issues, among others. The evaluation of these contingencies is performed by various specialists inside and outside of the group. Accounting for contingencies requires significant judgement by management regarding the estimated probabilities and ranges of exposure to potential loss. The directors’ assessment of the group’s exposure to contingencies could change as new developments occur or more information becomes available. The outcome of the contingencies could vary significantly and could materially impact the group’s results and financial position. The directors have used their best judgement in applying IAS 37 to these matters.

(vi) IFRS – RETIREMENT BENEFIT OBLIGATIONS

The group operates a number of defined benefit schemes for its employees which are accounted for in accordance with IAS 19 ‘Employee Benefits’ using the immediate recognition approach.

The group chooses a discount rate for each scheme which reflects yields on high-quality, fixed-income investments, specifically AA-rated corporate bonds of a similar duration to the liabilities. The discount rate used for the purposes of determining the IAS 19 pension charge for the year ended 31 March 2006 for the group’s principal continuing pension schemes, being the ScottishPower and Manweb pension schemes, was 5.4% for both schemes. The discount rate used for the purposes of determining the pension liability at 31 March 2006 and the pension charge for the year ending 31 March 2007 is 5.0% for both schemes. The pension liability and pension charge both increase as the discount rate is reduced. If the IAS 19 charge for the year ended 31 March 2006 and the pension liability at 31 March 2006 had been based on a discount rate 0.5% p.a. higher or lower than those actually used, the charge would have reduced or increased, respectively, by £7 million and the pension liability would have reduced or increased, respectively, by £240 million in respect of the group’s principal continuing pension schemes.

US GAAP

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assessments and these are discussed below. The discussion below should be read in conjunction with the full discussion of the differences between the group’s IFRS and US GAAP accounting policies set out in Note 44 to the Accounts.

(i)

US GAAP – DERIVATIVE FINANCIAL INSTRUMENTS

(ii) US GAAP – IMPAIRMENT OF GOODWILL

(iii) US GAAP – RETIREMENT BENEFIT OBLIGATIONS

The group accounts for its pension schemes under US GAAP in accordance with FAS 87 ‘Employers’ Accounting for Pensions’. Under FAS 87, certain of the group’s pension schemes had assets with a fair value at 31 March 2006 that was less than the accumulated benefit obligation under the schemes at the same date. As a result, at 31 March 2006 the group recognised a minimum pension liability under US GAAP of £159 million, of which £159 million was charged to accumulated other comprehensive income. The discount rate used for the purposes of calculating the charge under US GAAP for the group’s principal continuing pension schemes was 5.4%. The discount rate used to calculate the minimum pension liability at 31 March 2006 was 5.0%. If a discount rate had been used for accumulated benefit obligation purposes which was 0.5% p.a. higher or lower than that actually used, the impact would have been to reduce or increase, respectively, the minimum pension liability by £56 million in respect of the group’s principal continuing pension schemes.

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Accounts 2005/06

Group Income Statement

for the year ended 31 March 2006

Year

ended 31 March

Notes Before exceptional items and certain remeasurements 2006 £m Exceptional items and certain remeasurements (Note 2) 2006 £m Total 2006 £m Before exceptional items and certain remeasurements 2005 £m Exceptional items and certain remeasurements (Note 2) 2005 £m Total 2005 £m

Continuing

operations

Revenue

1 5,446.1 – 5,446.1 4,595.0 – 4,595.0

Cost

of sales 2 (3,965.7) – (3,965.7) (3,375.1) 93.2 (3,281.9)

Transmission

and distribution costs (327.3) – (327.3) (293.7) – (293.7)

Administrative

expenses before exceptional items (380.2) – (380.2) (380.4) – (380.4)

Exceptional

administrative expenses 2 – (101.0) (101.0) – – –

Administrative

expenses (380.2) (101.0) (481.2) (380.4) – (380.4)

Fair

value gains on operating derivatives 1, 2 – 85.3 85.3 – – –

Other

operating income 32.2 – 32.2 34.2 – 34.2

of loss of jointly controlled entities and associates 1 (0.6) – (0.6) – – –

Gain

on disposal of gas storage project 2 – 80.9 80.9 – – –

Operating

profit 1, 3, 10 804.5 65.2 869.7 580.0 93.2 673.2

Finance

income 5 186.4 – 186.4 212.2 – 212.2

Fair

value losses on financing derivatives 2, 6 – (115.4) (115.4) – – –

Finance

costs 7 (315.6) – (315.6) (333.0) – (333.0)

Net

finance costs (129.2) (115.4) (244.6) (120.8) – (120.8)

Profit

before tax 675.3 (50.2) 625.1 459.2 93.2 552.4

Income

tax 2, 8, 10 (161.7) 44.3 (117.4) (109.3) (28.1) (137.4)

Profit

for the year from continuing operations 513.6 (5.9) 507.7 349.9 65.1 415.0

Discontinued

operations

Profit/(loss)

for the year from discontinued operations 9, 10 299.9 736.1 1,036.0 318.2 (921.9) (603.7)

Profit/(loss)

for the financial year 813.5 730.2 1,543.7 668.1 (856.8) (188.7)

Attributable

to:

Equity

holders of Scottish Power plc 33 813.1 730.2 1,543.3 663.4 (856.8) (193.4)

Minority

interest

–

equity 34 0.4 – 0.4 1.3 – 1.3

–

non-equity 34 – – – 3.4 – 3.4

813.5

730.2 1,543.7 668.1 (856.8) (188.7)

Basic

earnings/(loss) per share 10

–

Continuing operations 27.54p 22.60p

–

Discontinued operations 56.23p (33.16)p

–

Continuing and discontinued operations 83.77p (10.56)p

Adjusted

basic earnings per share 10

–

Continuing operations 27.85p 19.04p

–

Discontinued operations 16.28p 17.20p

–

Continuing and discontinued operations 44.13p 36.24p

Diluted

earnings/(loss) per share 10

–

Continuing operations 27.33p 22.03p

–

Discontinued operations 55.82p (31.49)p

–

Continuing and discontinued operations 83.15p (9.46)p

Adjusted

diluted earnings per share 10

–

Continuing operations 27.12p 18.65p

–

Discontinued operations 15.40p 16.33p

–

Continuing and discontinued operations 42.52p 34.98p

Dividends

per share

Dividends

per ordinary share (paid and proposed) 11 25.00p 22.50p

The Accounting Policies and Definitions and Critical Accounting Judgements and Key Sources of Estimation Uncertainty on pages 70 to 83, together with the Notes on pages

to 155, form part of these Accounts.

84 ScottishPower Annual Report & Accounts 2005/06

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Group Statement of Recognised Income and Expense

for the year ended 31 March 2006

Year ended 31 March

2006

2005

£m

Gains

on effective cash flow hedges recognised 747.9 –

Exchange

movement on translation of overseas results and net assets 244.1 (100.2)

(Losses)/gains

on net investment hedges (276.5) 146.6

Gains

on revaluation of available-for-sale securities 0.4 –

Actuarial

gains/(losses) on retirement benefits 39.1 (63.3)

Tax

on items taken directly to equity (193.2) (27.5)

Net

income/(expense) recognised directly in equity for the year 561.8 (44.4)

Profit/(loss)

for the year 1,543.7 (188.7)

Total

income and expense for the year 2,105.5 (233.1)

Cumulative

adjustment for the implementation of IAS 39 (net of tax) 281.4 –

Cumulative translation gain transferred to income statement on disposal of discontinued operations (net of tax) (484.6) –

Gains removed from equity and recognised in the year (484.5) –

Tax on items transferred from equity 145.4 –

Total recognised income and expense 1,563.2 (233.1)

All of the above movements are reflected in Note 33.

Total income and expense for the year attributable to:

Equity holders of Scottish Power plc 2,105.1 (237.8)

Minority interests

– equity 0.4 1.3

– non-equity – 3.4

2,105.5 (233.1)

The Accounting Policies and Definitions and Critical Accounting Judgements and Key Sources of Estimation Uncertainty on pages 70 to 83, together with the Notes on pages 89 to 155, form part of these Accounts.

ScottishPower Annual Report & Accounts 2005/06 85

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Accounts 2005/06

Group Cash Flow Statement

for the year ended 31 March 2006

Year ended

March

2006

2005

Notes

£m £m

Continuing

operations

Operating

activities

Cash

generated from operations 12 864.5 681.4

Dividends

received from jointly controlled entities 1.4 2.0

Interest

paid (214.5) (131.5)

Interest

received 71.3 31.0

Income

taxes paid (74.8) (56.2)

Reallocation

from discontinued operations 67.8 122.2

Net

cash from operating activities 715.7 648.9

Continuing

operations

Investing

activities

Purchase

of intangible assets (57.3) (21.5)

Proceeds

from sale of intangible assets 3.2 –

Purchase

of property, plant and equipment (940.3) (421.2)

Proceeds

from sale of property, plant and equipment 21.4 19.0

Investment

in jointly controlled entities and (purchase)/sale of other investments (72.8) 18.8

Deferred

income received 25.3 25.6

Deferred

income repaid (2.5) (37.3)

Purchase

of subsidiaries and jointly controlled entities 13 (9.0) (343.7)

Sale

of businesses and subsidiaries 13 2,850.9 (7.4)

Equity

investment in discontinued operations (271.4) –

Dividend

received from discontinued operations 97.8 104.8

Net

cash provided by/(used in) investing activities 1,645.3 (662.9)

Continuing

operations

Financing

activities

Issue

of share capital 35.1 21.9

buy-back (10.4) –

Dividends

paid to company’s equity holders (428.1) (386.1)

Dividends

paid to minority interests (2.5) (1.0)

Net

consideration received/(paid) in respect of own shares held under trust 27.0 (23.3)

Repayments

of borrowings (102.8) (295.6)

Proceeds

from borrowings – 783.6

Reallocation

from discontinued operations 61.7 232.0

Net

cash (used in)/provided by financing activities (420.0) 331.5

Net

increase in net cash and cash equivalents – continuing operations 14 1,941.0 317.5

Net

(decrease)/increase in net cash and cash equivalents – discontinued operations 9 (103.7) 83.4

Net

increase in net cash and cash equivalents 1,837.3 400.9

86 ScottishPower Annual Report & Accounts 2005/06

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Movement in Net Cash and Cash Equivalents

for the year ended 31 March 2006

Year ended

March

2006

2005

Notes

£m £m

Net

cash and cash equivalents at beginning of year 1,727.3 1,327.2

Less:

Net cash and cash equivalents at beginning of year – discontinued operations 97.4 14.4

Net

cash and cash equivalents at beginning of year – continuing operations 1,629.9 1,312.8

Increase

in net cash and cash equivalents on implementation of IAS 39 on 1 April 2005 43 0.7 –

Net

cash and cash equivalents at 1 April 2005 as restated under IFRS – continuing operations 1,630.6 1,312.8

Net

increase in net cash and cash equivalents 1,941.0 317.5

Effect

of foreign exchange rate changes 7.4 (0.4)

Mark

to market movements on certain money market funds 4.0 –

Net

cash and cash equivalents at end of year – continuing operations (a) 3,583.0 1,629.9

(a) Net cash and cash equivalents in respect of continuing operations at 31 March 2006 comprises cash and cash equivalents of £3,584.4 million less bank overdrafts of £1.4 million. An analysis of net cash and cash equivalents is set out in Note 14.

Reconciliation of Movement in Net Cash and Cash Equivalents to Movement in Net Debt

for the year ended 31 March 2006

Year ended 31 March

2006

£m

Net

debt at beginning of year (4,334.8)

Less:

Net debt at beginning of year – discontinued operations (2,307.6)

Net

debt at beginning of year – continuing operations (2,027.2)

Decrease

in net debt on implementation of IAS 39 on 1 April 2005 – continuing operations 0.5

Net

debt at 1 April 2005 as restated under IFRS – continuing operations (2,026.7)

Net

increase in net cash and cash equivalents 1,941.0

Outflow

of net cash and cash equivalents from decrease in debt 102.8

Foreign

exchange (113.2)

Mark-to-market

movements on net debt 11.3

Other

non-cash and cash equivalent movements 2.1

Net

debt at end of year – continuing operations (82.7)

An analysis of net debt is set out in Note 14.

ScottishPower Annual Report & Accounts 2005/06 87

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Accounts 2005/06

? Group Balance Sheet

as at 31 March 2006

2006

2005

Notes

£m £m

Non-current

assets

Intangible

assets

goodwill 16 100.8 885.1

other intangible assets 16 147.6 409.5

Property,

plant and equipment 17 5,489.8 9,334.9

Investments

accounted for using the equity method 18 126.7 53.1

Other

investments 19 4.1 120.3

Trade

and other receivables 21 10.7 56.2

Derivative

financial instruments 23,25 602.4 -

Finance

lease receivables 22 104.6 158.4

Non-current

assets 6,586.7 11,017.5

Current

assets

Inventories

20 207.5 185.4

Trade

and other receivables 21 1,444.3 1,675.5

Derivative

financial instruments 23,25 867.5 -

Finance

lease receivables 22 20.5 17.3

Cash

and cash equivalents 14 3,584.4 1,747.8

Current

assets 6,124.2 3,626.0

Total

assets 15 12,710.9 14,643.5

Current

liabilities

Loans

and other borrowings 24 (523.0) (912.5)

Derivative

financial instruments 24,25 (426.6) -

Obligations

under finance leases 27 (6.7) (14.5)

Trade

and other payables 28 (1,369.7) (1,632.9)

Current

tax liabilities (406.3) (338.9)

Provisions

30 (26.5) (80.1)

Current

liabilities (2,758.8) (2,978.9)

Non-current

liabilities

Loans

and other borrowings 24 (3,079.4) (4,996.8)

Derivative

financial instruments 24,25 (149.7) -

Obligations

under finance leases 27 (58.0) (158.8)

Trade

and other payables 28 (36.6) (2.7)

Retirement

benefit obligations 35 (155.5) (635.5)

Deferred

tax liabilities 29 (823.3) (1,161.4)

Provisions

30 (65.8) (182.2)

Deferred

income 31 (482.8) (570.1)

Non-current

liabilities (4,851.1) (7,707.5)

Total

liabilities 15 (7,609.9) (10,686.4)

Net

assets 5,101.0 3,957.1

Equity

capital 32,33 935.6 932.7

premium 33 2,326.0 2,294.7

Hedge

reserve 33 595.2 -

Translation

reserve 33 8.2 484.6

Other

reserves 33 431.4 430.5

Retained

earnings/(loss) 33 804.5 (241.1)

Equity

attributable to equity holders of Scottish Power plc 15 5,100.9 3,901.4

Minority

interests

-equity

34 0.1 3.2

non-equity 34—52.5

Total

equity 5,101.0 3,957.1

Net

asset value per share 15 275.7p 212.9p

Approved by the Board on 24 May 2006 and signed on its behalf by

Charles Miller Smith Simon Lowth

Chairman Finance Director

ScottishPower Annual Report & Accounts 2005/06

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Notes to the Group Accounts

for the year ended 31 March 2006

Segmental income statement information

For management purposes, the group is currently organised into three continuing operating businesses, Energy Networks (formerly Infrastructure Division – Power Systems), Energy Retail & Wholesale (formerly UK Division – Integrated Generation and Supply) and PPM Energy and therefore reports its primary segment information on this basis. PacifiCorp, the group’s former regulated US business, is included within the discontinued operations segment following the group’s decision on 24 May 2005 to dispose of the business. The results of this discontinued operation are disclosed in Note 9.

The group has also reviewed the classification, for segmental purposes, of revenue and operating profit relating to corporate activities (previously allocated across business segments) and to the non-regulated businesses (previously included within the PacifiCorp segment) which were not included in the sale of PacifiCorp. These are now included within ‘Unallocated’ in the segmental analyses below.

(a)

Revenue by segment Total revenue Inter-segment revenue External revenue

2006

2005 2006 2005 2006 2005

Notes

£m £m £m £m £m £m

Continuing

operations

United

Kingdom

Energy

Networks 861.7 728.9 (299.5) (348.8) 562.2 380.1

Energy

Retail & Wholesale 4,344.4 3,712.5 (17.1) (27.5) 4,327.3 3,685.0

United

Kingdom total 5,206.1 4,441.4 (316.6) (376.3) 4,889.5 4,065.1

Continuing

operations

United

States

PPM

Energy 545.9 502.0 – – 545.9 502.0

United

States total 545.9 502.0 – – 545.9 502.0

Unallocated

revenue (i) 10.7 27.9

Total

(ii) 5,446.1 4,595.0

(i) Unallocated revenue comprises revenue of the non-regulated businesses, previously included within the PacifiCorp segment, which were not included in the sale of PacifiCorp. (ii) In the segmental analysis revenue is shown by geographical origin. Revenue analysed by geographical destination is not materially different.

(b)

Operating profit by segment

Notes Before fair value gains/(losses) on operating derivatives and exceptional items 2006 £m Fair value gains/(losses) on operating derivatives (Note 2) 2006 £m Exceptional items (Note 2) 2006 £m Fair value gains/(losses) on operating derivatives and exceptional items 2006 £m Total 2006 £m Before certain remeasurements 2005 £m Certain remeasurements (Note 2) 2005 £m Total 2005 £m

Continuing

operations

United

Kingdom

Energy

Networks (iii) 524.6 – (18.0) (18.0) 506.6 427.4 – 427.4

Energy

Retail & Wholesale (iii) 214.1 88.7 72.2 160.9 375.0 93.5 91.8 185.3

United

Kingdom total 738.7 88.7 54.2 142.9 881.6 520.9 91.8 612.7

Continuing

operations

United

States

PPM

Energy (iii) 90.6 (3.0) (34.6) (37.6) 53.0 58.6 1.4 60.0

United

States total 90.6 (3.0) (34.6) (37.6) 53.0 58.6 1.4 60.0

Unallocated

(expense)/income (i), (iii) (24.8) (0.4) (39.7) (40.1) (64.9) 0.5 – 0.5

Total

(ii), (iii) 804.5 85.3 (20.1) 65.2 869.7 580.0 93.2 673.2

(i) Unallocated (expense)/income comprises corporate office costs and the operating results of the non-regulated businesses, previously included within the PacifiCorp segment, which were not included in the sale of PacifiCorp.

(ii) Share of (loss)/profit in jointly controlled entities and associates included in operating profit by segment for the year ended 31 March 2006 is as follows: Energy Networks £(3.5) million (2005 £0.2 million), Energy Retail & Wholesale £1.4 million (2005 £(1.9) million), PPM Energy £1.5 million (2005 £(0.5) million) and unallocated income £nil (2005 £2.2 million).

(iii) The reconciliation of operating profit for the year ended 31 March 2005 under UK GAAP on the previous segmental basis to operating profit under IFRS on the revised segmental basis is provided below.

Reconciliation

of adjusted operating profit by segment for the prior year Year ended 31 March 2005

Energy Networks £m Energy Retail & Wholesale £m PPM Energy £m Unallocated (expense)/income £m Total £m

Operating

profit* under UK GAAP – previous segmental basis 416.3 180.5 58.6 – 655.4

Reallocation

of corporate costs 8.7 15.3 1.3 (38.2) (12.9)

Reallocation

of PacifiCorp non-regulated businesses – – – 39.1 39.1

Operating

profit* under UK GAAP – revised segmental basis 425.0 195.8 59.9 0.9 681.6

IFRS

adjustments 2.2 (8.6) 0.6 (2.6) (8.4)

Reclassification

of jointly controlled entities and associates 0.2 (1.9) (0.5) 2.2 –

Operating

profit* under IFRS – revised segmental basis 427.4 185.3 60.0 0.5 673.2

*before goodwill amortisation and exceptional item for UK GAAP and before exceptional item for IFRS.

ScottishPower Annual Report & Accounts 2005/06 89

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

Segmental income statement information continued

(c)

Amortisation and depreciation by segment Amortisation Depreciation

2006

2005 2006 2005

£m

£m £m £m

Continuing

operations

United

Kingdom

Energy

Networks 7.4 7.7 99.9 98.6

Energy

Retail & Wholesale 20.2 61.3 94.8 88.6

United

Kingdom total 27.6 69.0 194.7 187.2

Continuing

operations

United

States

PPM

Energy 3.4 1.3 12.1 12.0

United

States total 3.4 1.3 12.1 12.0

Unallocated

1.5 1.0 9.3 8.4

Total

32.5 71.3 216.1 207.6

(d)

Fair value gains on operating derivatives by segment

Included in operating profit above are fair value gains on operating derivatives as follows:

Unwind of opening position Mark-to-market gains/(losses) Hedge ineffectiveness Total

2006 £m 2005 £m 2006 £m 2005 £m 2006 £m 2005 £m 2006 £m 2005 £m

Continuing

operations

United

Kingdom

Energy

Networks – – – – – – – –

Energy

Retail & Wholesale – – 92.7 – (4.0) – 88.7 –

United

Kingdom total – – 92.7 – (4.0) – 88.7 –

Continuing

operations

United

States

PPM

Energy 110.6 – (114.3) – 0.7 – (3.0) –

United

States total 110.6 – (114.3) – 0.7 – (3.0) –

Unallocated

– – (0.4) – – – (0.4) –

Total

110.6 – (22.0) – (3.3) – 85.3 –

(e)

Significant non-cash expenditure by segment Impairment of trade receivables

2006

2005

£m

Continuing

operations

United

Kingdom

Energy

Networks 0.3 –

Energy

Retail & Wholesale 55.8 41.3

United

Kingdom total 56.1 41.3

Continuing

operations

United

States

PPM

Energy – –

United

States total – –

Unallocated

– –

Total

56.1 41.3

Other

significant non-cash expenditures are disclosed in Note 2.

90 ScottishPower Annual Report & Accounts 2005/06

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Exceptional items and certain remeasurements

Exceptional items and certain remeasurements included in profit for the year from continuing operations are as follows:

2006

2005

Notes

£m £m

(a)

Exceptional administrative expenses

Corporate

restructuring costs (i) (42.0) –

Impairment

of finance lease receivables (ii) (25.4) –

Credit

support facility costs (iii) (33.6) –

(101.0)

–

(b)

Gain on disposal of gas storage project (iv) 80.9 –

Total

exceptional items 10 (20.1) –

(c)

IAS 39 adjustments

Onerous

contract releases/intangible assets charges relating to commodity contracts in prior year 10 – 92.4

Proprietary

trading profit in prior year 10 – 0.8

Fair

value gains on operating derivatives in current year 1, 10 85.3 –

Fair

value losses on financing derivatives in current year 6, 10 (115.4) –

Total

IAS 39 adjustments (30.1) 93.2

Tax

on exceptional items and certain remeasurements

Tax

on exceptional administrative expenses 35.1 –

Tax

on IAS 39 adjustments 9.2 (28.1)

44.3

(28.1)

Total

exceptional items and certain remeasurements (net of tax) (5.9) 65.1

(i) A gross exceptional charge of £42.0 million and related tax credit of £12.7 million relating to costs of the corporate restructuring. Costs of the corporate restructuring by segment for the year ended 31 March 2006 are as follows: Energy Networks £18.0 million, Energy Retail & Wholesale £8.7 million, PPM Energy £1.0 million and Unallocated expense £14.3 million.

(ii) A gross exceptional charge of £25.4 million and related tax credit of £9.6 million relating to the impairment of the group’s aircraft leases within the Unallocated segment. (iii) A gross exceptional charge of £33.6 million and related tax credit of £12.8 million within PPM Energy relating to probable liabilities in relation to a credit support facility provided by PacifiCorp Holdings Inc. (now ScottishPower Holdings Inc.) to certain providers of debt to the Klamath Co-Generation project at the project’s inception in 1999. The project is owned by the City of Klamath Falls, but operated by PPM Energy which has a purchase contract for 47% of the output.

(iv) A gross exceptional gain within Energy Retail & Wholesale of £80.9 million relating to the sale of the group’s underground natural gas storage project at Byley to E.ON UK plc for £96.0 million. There is no tax effect of this exceptional item.

Operating profit

2006

2005

(a)

Operating profit from continuing operations is stated after charging/(crediting): £m £m

Amortisation

of intangible assets 32.5 71.3

Depreciation

of property, plant and equipment 216.1 207.6

Release

of grants and customer contributions (19.7) (17.5)

Research

and development 0.3 0.2

2006

2005

(b)

Auditors’ remuneration £m £m

Audit

services

–

statutory audit 1.2 1.1

–

audit-related regulatory reporting 0.3 0.5

Further

assurance services 0.3 1.8

Tax

services

–

compliance services 0.5 0.4

–

advisory services 0.2 0.4

Other

services 0.1 –

Total

UK and US audit and non-audit fees paid to auditors for continuing operations 2.6 4.2

Audit

services

–

statutory audit 0.8 0.6

–

audit-related regulatory reporting 0.2 0.2

Further

assurance services 1.1 0.7

Tax

services

–

compliance services 0.7 0.6

–

advisory services 1.6 –

Other

services – –

audit and non-audit fees paid to auditors for discontinued operations 4.4 2.1

Total

UK and US audit and non-audit fees paid to auditors 7.0 6.3

ScottishPower Annual Report & Accounts 2005/06 91

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

Operating profit continued

The policy on non-audit services prohibits the use of the external audit firm for specified services. It is considered appropriate, for commercial and practical reasons, including confidentiality, to use the external auditors for certain non-audit services. These permissible services are set out in the policy and have been pre-approved by the Audit Committee up to an initial fee value of £100,000 per assignment. Permissible services that are not listed in the policy require to be pre-approved individually by the Audit Committee or its Chairman; any assignments that exceed the fee limit must be reviewed and authorised by the Committee Chairman and the Finance Director.

For the year ended 31 March 2006, of the total audit and non-audit fees paid to the auditors of £7.0 million (2005 £6.3 million), £4.5 million (2005 £5.6 million) was charged to operating profit and £2.5 million was charged against the gain on disposal of PacifiCorp (2005 £0.7 million was included in the cost of acquisitions).

For the year ended 31 March 2006, fees for ‘Further assurance services’ and ‘Tax advisory services’ principally relate to services provided in connection with the disposal of PacifiCorp and the capital reorganisation and return of cash to shareholders. For the year ended 31 March 2005, fees for ‘Further assurance services’ principally relate to due diligence work on acquisitions and advice regarding the implementation of s404 of the Sarbanes-Oxley Act and the implementation of IFRS.

Employee information

2006

2005

(a)

Employee costs £m £m

Wages

and salaries 308.2 268.2

Social

security costs 23.5 21.5

Pension

and other costs 44.8 37.8

Total

employee costs 376.5 327.5

Less:

charged as capital expenditure (75.9) (65.4)

Charged

to the income statement 300.6 262.1

(b)

Employee numbers

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

31 March Annual average

2006

2005 2006 2005

Continuing

operations

United

Kingdom

Energy

Networks 3,380 3,328 3,394 3,260

Energy

Retail & Wholesale 5,512 5,386 5,646 4,970

United

Kingdom total 8,892 8,714 9,040 8,230

Continuing

operations

United

States

PPM

Energy 371 278 363 240

United

States total 371 278 363 240

Unallocated

530 504 550 461

Total

9,793 9,496 9,953 8,931

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

31 March Annual average

2006

2005 2006 2005

United

Kingdom 8,425 8,269 8,543 7,955

United

States 370 277 363 240

Unallocated

516 480 534 433

Total

9,311 9,026 9,440 8,628

(c)

Directors’ remuneration

Details, for each director, of remuneration, pension entitlements and interests in share options are set out in Tables 33 to 36 on pages 63 to 68. This information forms part

the Accounts.

92 ScottishPower Annual Report & Accounts 2005/06

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Finance income

2006

2005

£m

Interest

on bank and other deposits 66.8 60.4

Interest

on finance lease receivables 7.0 42.5

Foreign

exchange gains 2.2 2.0

Expected

return on retirement benefit assets 110.4 107.3

Total

finance income 186.4 212.2

Fair value losses on financing derivatives

Fair value losses on financing derivatives of £115.4 million include losses of £125.1 million for the year ended 31 March 2006, resulting from changes to the fair value of the

embedded derivative within the $700 million convertible bonds, primarily as a result of movement in the company’s ordinary share price.

Finance costs 2006 2005

Notes

£m £m

Interest

on bank loans and overdrafts 13.0 18.8

Interest

on other borrowings 204.2 164.6

Interest

on obligations under finance leases 6.0 40.1

Capitalised

interest (a) (8.2) (1.7)

Unwinding

of discount on provisions 0.9 10.4

Interest

on retirement benefit obligations 99.7 100.8

Total

finance costs 315.6 333.0

Interest

cover (times) (b) 6.1 4.7

(a)

The tax relief on the capitalised interest was £0.9 million (2005 £0.5 million).

(b) Interest cover is calculated by dividing operating profit before exceptional items and certain remeasurements by the sum of the total finance income (less foreign exchange gains) and total finance costs.

Income tax

2006

2005

£m

Current

tax:

Corporation tax 238.0 184.5

Adjustments

in respect of prior years (9.1) (40.7)

Total

UK Corporation tax for year 228.9 143.8

Foreign

tax (61.8) (14.2)

Adjustments

in respect of prior years 15.7 7.6

Total

foreign tax for year (46.1) (6.6)

Total

current tax for year 182.8 137.2

Deferred

tax:

Origination

and reversal of timing differences (25.3) 3.1

Adjustments

in respect of prior years (40.1) (2.9)

Total

deferred tax for year (65.4) 0.2

Total

income tax expense 117.4 137.4

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

2006

2005

£m

Corporation

tax at 30% 187.5 165.7

Effect

of tax rate applied to overseas earnings (16.7) 6.9

Adjustments

in respect of prior years (33.5) (36.0)

Utilisation

of UK capital losses (24.3) –

Other

permanent differences 4.4 0.8

Income

tax expense for the year 117.4 137.4

ScottishPower Annual Report & Accounts 2005/06 93

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

9 Discontinued operations

On 24 May 2005, the group entered into a sale agreement to dispose of PacifiCorp, the group’s former US regulated business. This operation was classified as a disposal group held for sale and a discontinued operation in accordance with IFRS 5 as of that date. The disposal was completed on 21 March 2006, on which date control of PacifiCorp passed to MidAmerican. The results of the discontinued operation for the period to 20 March 2006 and year ended 31 March 2005, which have been included in the Group Income Statement, are as follows:

2006

2005

Notes

£m £m

Revenue

2,498.9 2,250.9

Fair

value gains on operating derivatives 64.6 –

Depreciation

and amortisation (a) (32.1) (216.2)

Exceptional

item – impairment of goodwill (b) – (922.0)

Other

net operating costs (1,721.8) (1,500.0)

Operating

profit/(loss) 809.6 (387.3)

Net

finance costs (c) (178.3) (66.7)

Profit/(loss)

before tax 631.3 (454.0)

Attributable

tax expense (214.7) (149.7)

Profit/(loss)

after tax from discontinued operations 416.6 (603.7)

Exceptional

item – gain on sale of PacifiCorp (e) 619.4 –

Profit/(loss)

for the period/year 1,036.0 (603.7)

(a) The depreciation and amortisation charge for the period to 20 March 2006 of £32.1 million represents the depreciation and amortisation charged for the period until 23 May 2005. Under IFRS 5, non-current assets held for sale are not subject to depreciation or amortisation and, therefore, the above results did not include charges of £190.8 million in relation to depreciation and amortisation for the period from 24 May 2005 to 20 March 2006.

(b) In November 2004, the Board began a strategic review of PacifiCorp as a result of its performance and the significant investment it required in the immediate future. In May 2005, the Board concluded that in light of the prospects for PacifiCorp, the scale and timing of the capital investment required and the likely profile of returns, shareholders’ interests were best served by a sale of PacifiCorp and a return of capital to shareholders. As a consequence, the group undertook a review of the carrying value of the goodwill allocated to the PacifiCorp reporting segment as at 31 March 2005. The estimated recoverable value was based on net realisable value, with reference to the price of comparable businesses, recent market transactions and the estimated proceeds from disposal. This resulted in an exceptional charge, in the year ended 31 March 2005, for impairment of goodwill of £922.0 million.

(c)

An analysis of net finance costs is given below:

2006

2005

£m

Interest

charge 174.5 158.7

Interest

receivable (20.6) (9.5)

Net

interest cost on retirement benefit obligations 3.8 5.9

157.7

155.1

Other

finance items allocated to discontinued operations:

Fair

value losses on financing derivatives 13.5 –

Interest

rate differential (39.0) (88.4)

Loss

following de-designation of net investment hedges 46.1 –

20.6

(88.4)

Net

finance costs 178.3 66.7

Net finance costs include the UK/US interest rate differential benefit of £39.0 million (2005 £88.4 million) arising from the group’s US dollar hedging programme relating to

PacifiCorp’s net assets for the year ended 31 March 2006. This programme has terminated following the sale of PacifiCorp on 21 March 2006.

(d) The cash flows of the discontinued operation, which have been included in the Group Cash Flow Statement, are as follows:

2006

2005

£m

Net

cash from operating activities – discontinued operations 569.9 404.6

Net

cash used in investing activities – discontinued operations (420.3) (471.3)

Net

cash (used in)/provided by financing activities – discontinued operations (253.3) 150.1

Net

(decrease)/increase in net cash and cash equivalents – discontinued operations (103.7) 83.4

94 ScottishPower Annual Report & Accounts 2005/06

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9 Discontinued operations continued

(e)

The gain on sale of PacifiCorp is analysed as follows: 21 March 2006

Notes

£m

Intangible

assets

–

goodwill 854.2

–

other intangible assets 215.4

Property,

plant and equipment 5,424.3

Investments

172.4

Other

non-current assets 128.3

Current

assets 530.8

Current

liabilities (749.4)

Non-current

liabilities (3,907.0)

Book

value of PacifiCorp net assets disposed 2,669.0

Book

gain on sale (pre-tax) (i) 122.5

Net

disposal proceeds 2,791.5

Satisfied

by:

Cash

received for net assets 2,911.4

Cash

expenses (26.2)

Net

disposal cash proceeds (ii) 2,885.2

Accrued

expenses (74.3)

Impairment

of assets (iii), 17 (19.4)

Net

disposal proceeds 2,791.5

(i)

The gain on sale of PacifiCorp comprises:

Book

gain on sale (pre-tax) 122.5

Tax

credit on sale (iv) 12.3

Cumulative

translation gains realised on sale – transferred from equity 33 484.6

Gain

on sale of PacifiCorp 619.4

(ii) The book gain on sale excludes cash outflows of £116.7 million relating to the settlement of certain treasury derivative financial instruments following the sale of PacifiCorp, which had previously been marked-to-market.

(iii) PPM Energy has leased a power plant to PacifiCorp since 2002. As part of the final settlement achieved with MidAmerican on completion of the sale of PacifiCorp, the group

agreed to a reduction in lease rentals receivable by PPM Energy from PacifiCorp in respect of this lease. As a consequence of this reduction in lease rentals, an impairment of £19.4 million has been charged against the gain on sale. Other sale expenses (cash and accrued) of £100.5 million principally comprise legal and other professional fees of £37.8 million and a provision of £32.9 million for royalties payable to MidAmerican.

(iv) The disposal of PacifiCorp gives rise to a net taxable capital loss for the group which is offset against other taxable capital gains made in the current year. As a result the gain

on sale has benefited from a tax credit of £12.3 million.

(f) The operating profit before goodwill amortisation and exceptional items for PacifiCorp for the year ended 31 March 2005 under UK GAAP on the previous segmental basis was

£541.7 million. The operating profit, as adjusted for exceptional items and contracts now within the scope of IAS 39, of PacifiCorp for the year ended 31 March 2005 under

IFRS on the revised segmental basis was £534.6 million. The movements comprise reallocation of corporate costs of £12.9 million, reallocation of PacifiCorp non-regulated

operating profit of £(39.1) million, IFRS adjustments of £19.2 million and adjustments for contracts now within the scope of IAS 39 of £(0.1) million.

(g) Employee costs of £334.4 million (2005 £307.6 million) were charged against the results of the discontinued operation for the period from 1 April 2005 to 20 March 2006.

These comprised wages and salaries of £364.4 million (2005 £310.8 million), social security costs of £23.4 million (2005 £19.5 million) and pension and other costs of £55.0

million (2005 £63.6 million) less amounts charged as capital expenditure of £108.4 million (2005 £86.3 million). The average number of employees (full-time and part-time),

including executive directors, employed by the discontinued operation during the year was 6,597 (2005 6,610).

ScottishPower Annual Report & Accounts 2005/06 95

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

10 Earnings per share and reconciliation of adjusted profits, earnings per share and diluted earnings per share

(a)

Earnings per share

Earnings per share have been calculated by dividing the profit/(loss) for the year (as adjusted for minority interests) by the weighted average number of ordinary shares in issue during the year, based on the following information:

2006

2005

£m

Basic

earnings per share

Profit/(loss)

attributable to equity holders of Scottish Power plc

–

Continuing 507.3 413.7

–

Discontinued 1,036.0 (607.1)

–

Continuing and Discontinued 1,543.3 (193.4)

Weighted

average share capital (number of shares, million) 1,842.4 1,830.8

Diluted

earnings per share

Profit/(loss)

attributable to equity holders of Scottish Power plc

–

Continuing 507.3 424.7

–

Discontinued 1,036.0 (607.1)

–

Continuing and Discontinued 1,543.3 (182.4)

Weighted

average share capital (number of shares, million) 1,856.0 1,928.0

The difference between the profit for the financial year from continuing operations for the purposes of the basic and the diluted earnings per share calculations is analysed as follows:

2006

2005

£m

Basic

earnings per share – profit for the financial year 507.3 413.7

Interest

on convertible bonds – 11.0

Diluted

earnings per share – profit for the financial year 507.3 424.7

The difference between the weighted average share capital for the purposes of the basic and the diluted earnings per share calculations is analysed as follows:

2006

2005

Number

of shares (million)

Basic

earnings per share – weighted average share capital 1,842.4 1,830.8

Outstanding

share options and shares held in trust for the group’s employee share schemes 13.6 6.2

Convertible

bonds – 91.0

Diluted

earnings per share – weighted average share capital 1,856.0 1,928.0

The group’s convertible bonds were dilutive for the year ended 31 March 2005 and anti-dilutive for the year ended 31 March 2006 based on the continuing profit attributable to equity

holders

of Scottish Power plc.

96 ScottishPower Annual Report & Accounts 2005/06

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10 Earnings per share and reconciliation of adjusted profits, earnings per share and diluted earnings per share continued

(b)

Reconciliation of adjusted profits, earnings per share and diluted earnings per share

Set out below are the reconciliations of adjusted profits, earnings per share and diluted earnings per share which have been prepared in accordance with the methodology set out in Group Accounting Policy ‘A. Basis of accounting’ on page 71.

2006

2005

Adjusted

profit from continuing operations Note £m £m

Continuing

operations

Operating

profit 869.7 673.2

IAS

39 adjustments

–

onerous contract releases/intangible assets charges

relating

to commodity contracts in prior year – (92.4)

–

proprietary trading profit in prior year – (0.8)

–

fair value gains on operating derivatives in current year (85.3) –

Other

items

–

exceptional items 2 20.1 –

Adjusted

operating profit 804.5 580.0

Net

finance costs (244.6) (120.8)

IAS

39 adjustments

–

fair value losses on financing derivatives in current year 115.4 –

Adjusted

net finance costs (129.2) (120.8)

Adjusted

profit before tax 675.3 459.2

Tax

(117.4) (137.4)

–

tax on adjusting items (44.3) 28.1

Adjusted

tax (161.7) (109.3)

Adjusted

profit from continuing operations 513.6 349.9

2006

2005

Adjusted

profit from discontinued operations Note £m £m

Discontinued

operations

Profit/(loss)

for the period from discontinued operations 9 1,036.0 (603.7)

IAS

39 adjustments

–

proprietary trading loss in prior year – (0.1)

–

fair value gains on operating derivatives in current year (64.6) –

–

fair value losses on financing derivatives in current year 13.5 –

–

loss following de-designation of net investment hedges 46.1 –

Other

items

–

gain on sale of discontinued operations before tax 9 (607.1) –

–

PacifiCorp depreciation 24 May 2005 – 20 March 2006 9 (190.8) –

–

impairment of PacifiCorp goodwill 9 – 922.0

Tax

on adjusting items 66.8 –

Net

adjusting items (736.1) 921.9

Adjusted

profit from discontinued operations 299.9 318.2

2006

2005

Adjusted

total profit attributable to equity holders of Scottish Power plc £m £m

Adjusted

total profit for the year 813.5 668.1

Minority

interests (0.4) (4.7)

Adjusted

total profit attributable to equity holders of Scottish Power plc 813.1 663.4

2006

2005

Adjusted

total basic earnings per share £m £m

Weighted

average share capital (number of shares, million) 1,842.4 1,830.8

Adjusted

total basic earnings per share 44.13p 36.24p

2006

2005

Adjusted

continuing basic earnings per share £m £m

Adjusted

profit from continuing operations 513.6 349.9

Minority

interests (0.4) (1.3)

Adjusted

continuing profit attributable to equity holders of Scottish Power plc 513.2 348.6

Adjusted

continuing basic earnings per share 27.85p 19.04p

ScottishPower Annual Report & Accounts 2005/06 97

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

10 Earnings per share and reconciliation of adjusted profits, earnings per share and diluted earnings per share continued

2006

2005

Adjusted

diluted earnings per share £m £m

Basic

earnings per share—adjusted total profit attributable to equity holders of Scottish Power plc 813.1 663.4

Interest

on convertible bonds 14.9 11.0

Diluted

earnings per share—adjusted total profit attributable to equity holders of Scottish Power plc 828.0 674.4

Basic

earnings per share—weighted average share capital (number of shares, million) 1,842.4 1,830.8

Outstanding

share options and shares held in trust for the group’s employee share schemes 13.6 6.2

Convertible

bonds 91.4 91.0

Diluted

earnings per share—weighted average share capital (number of shares, million) 1,947.4 1,928.0

Adjusted

total diluted earnings per share 42.52p 34.98p

Basic earnings per share—adjusted profit from continuing operations attributable to equity holders of Scottish Power plc 513.2 348.6

Interest

on convertible bonds 14.9 11.0

Diluted earnings per share—adjusted profit from continuing operations attributable to equity holders of Scottish Power plc 528.1 359.6

Adjusted

diluted earnings per share from continuing operations 27.12p 18.65p

The group’s convertible bonds were dilutive for the years ended 31 March 2006 and 31 March 2005 based on the adjusted profit from continuing operations attributable to

equity

holders of Scottish Power plc.

Dividends

2006

2005

pence

per pence per

ordinary

ordinary 2006 2005

share £m £m

Final

dividend paid for prior year 7.65 6.25 139.4 112.9

First

interim dividend paid 5.20 4.95 96.0 91.1

Second

interim dividend paid 5.20 4.95 96.3 91.0

Third

interim dividend paid 5.20 4.95 96.4 91.1

Total

dividends paid 23.25 21.10 428.1 386.1

Proposed

final dividend 9.40 7.65 138.6 139.4

The proposed final dividend of 9.40 pence per ordinary share is payable on 28 June 2006 to shareholders on the register at 2 June 2006. The proposed final dividend is payable on the new ordinary shares issued as part of the capital restructuring and return of cash to shareholders as explained in more detail in Note 41. The proposed final dividend was approved by the Board on 24 May 2006 and as required by IAS 10 ‘Events After the Balance Sheet Date’ has not been included as a liability in these Accounts.

98 ScottishPower Annual Report & Accounts 2005/06

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12 Reconciliation of operating profit to cash generated from continuing operations

2006

2005

£m

Operating

profit 869.7 673.2

Adjustments

for:

Fair

value gains on operating derivatives (85.3) –

of loss in jointly controlled entities and associates 0.6 –

Exceptional

items 20.1 –

Amortisation

32.5 71.3

Depreciation

216.1 207.6

Loss/(profit)

on sale of property, plant and equipment 4.2 (0.8)

Amortisation

of share scheme costs 7.5 5.6

Release

of deferred income (19.7) (17.5)

Movement

in provisions 14.6 (151.5)

Operating

cash flows before movements in working capital 1,060.3 787.9

(Increase)/decrease

in inventories (96.7) 6.9

Increase

in trade and other receivables (356.4) (312.8)

Increase

in trade payables 257.3 199.4

Cash

generated from continuing operations 864.5 681.4

13 Analysis of cash flows in respect of acquisitions and disposals

Acquisition

2006 Disposals 2006 Acquisitions 2005 Disposals 2005

£m

£m £m £m

Cash

consideration for jointly controlled entities including expenses – – (18.3) –

Cash

consideration for subsidiaries including expenses (9.0) 2,852.0 (352.2) –

Cash

and cash equivalents acquired – – 26.8 –

Expenses

and other costs paid in respect of prior year disposals – (1.1) – (7.4)

(9.0)

2,850.9 (343.7) (7.4)

In 2006, the cash flows in respect of the acquisition represent the remaining 50% of Core Utility Solutions Limited acquired from Alfred McAlpine. The cash flows in respect of disposals principally represent the sale of PacifiCorp (£2,885.2 million), the group’s former regulated US business and associated settlement of certain treasury derivative financial instruments (£(116.7) million), and the sale of the group’s underground natural gas storage project at Byley to E.ON UK plc (£83.5 million).

In 2005, the cash flows in respect of the acquisition of subsidiaries represented the purchase of Damhead Creek, the remaining 50% of Brighton Power Station and Atlantic Renewable Energy Corporation. The cash flows in respect of the acquisition of jointly controlled entities represents PPM Energy’s investment in the Maple Ridge joint venture. The cash flows in respect of disposals principally represented expenses and other costs related to prior year disposals.

14 Analysis of net debt

At 1 April 2005 Less: Net debt at 1 April 2005 -discontinued operations (Note (a)) Net debt at 1 April 2005 -continuing operations Implementation of IAS 39 at 1 April 2005 -continuing operations (Note (b)) Net debt at 1 April 2005 -continuing operations Cash flow Exchange Other non-cash changes (Note (c)) Net debt at 31 March 2006 -continuing operations

£m

£m £m £m £m £m £m £m £m

Cash

at bank and other deposits 1,747.8 116.6 1,631.2 0.7 1,631.9 1,941.0 7.5 4.0 3,584.4

Overdrafts

(20.5) (19.2) (1.3) – (1.3) – (0.1) – (1.4)

Net

cash and cash equivalents 1,727.3 97.4 1,629.9 0.7 1,630.6 1,941.0 7.4 4.0 3,583.0

Debt

due after one year (4,996.8) (1,920.9) (3,075.9) (18.9) (3,094.8) 6.8 (77.8) 86.4 (3,079.4)

Debt

due within one year (892.0) (399.3) (492.7) 18.7 (474.0) 96.0 (34.9) (108.7) (521.6)

Finance

leases (173.3) (84.8) (88.5) – (88.5) – (7.9) 31.7 (64.7)

102.8

Total

(4,334.8) (2,307.6) (2,027.2) 0.5 (2,026.7) 2,043.8 (113.2) 13.4 (82.7)

(a) On 24 May 2005, the components of net debt relating to the PacifiCorp disposal group were reclassified as ‘Assets classified as held for sale’ and ‘Liabilities classified as held for sale’ in accordance with IFRS 5.

(b) On the implementation of IAS 39 on 1 April 2005, certain components of net debt were remeasured resulting in a £0.5 million decrease in net debt.

(c) ‘Other non-cash changes’ to net debt represents amortisation of finance costs of £(2.2) million, finance costs of £(8.3) million representing the effects of the RPI on bonds carrying an RPI coupon, reclassifications to other balance sheet categories of £(19.1) million, fair value hedge adjustments to the carrying value of debt instruments of £11.3 million and a decrease of £31.7 million, relating to the financing of the group’s US aircraft portfolio. In addition, £100.0 million of debt due after one year has become due within one year.

ScottishPower Annual Report & Accounts 2005/06 99

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

15 Segmental balance sheet information

(a)

Total assets and liabilities by segment

Total assets Total liabilities

31 March 2006 £m 31 March 2005 £m 31 March 2006 £m 31 March 2005 £m

Notes

Continuing operations

United Kingdom

Energy Networks 3,385.4 3,157.8 (750.1) (694.9)

Energy Retail & Wholesale 4,023.1 2,579.0 (1,082.5) (805.1)

United Kingdom total 7,408.5 5,736.8 (1,832.6) (1,500.0)

Continuing operations

United States

PPM Energy 1,400.7 667.5 (410.8) (195.2)

United States total 1,400.7 667.5 (410.8) (195.2)

Total continuing operations 8,809.2 6,404.3 (2,243.4) (1,695.2)

Discontinued operations – PacifiCorp (United States) – 5,916.1 – (1,068.4)

Unallocated assets/(liabilities) (i) 3,901.7 2,323.1 (5,366.5) (7,922.8)

Total (ii) 12,710.9 14,643.5 (7,609.9) (10,686.4)

(i) Unallocated assets/(liabilities) include net debt, tax liabilities, retirement benefit obligations, investments and treasury-related derivatives. Unallocated assets/(liabilities) at

31 March 2005 relate to both continuing and discontinued operations. Unallocated assets/(liabilities) at 31 March 2006 relate solely to continuing operations. (ii) Investments in jointly controlled entities and associates included in total assets by segment are as follows: Energy Networks £nil (2005 £3.2 million), Energy Retail & Wholesale £10.8 million (2005 £11.1 million), PPM Energy £115.9 million (2005 £38.8 million) and Unallocated assets/(liabilities) £nil (2005 £nil).

(b)

Net asset value per share

Net asset value per share has been calculated based on net assets (after adjusting for minority interests) and the number of shares in issue (after adjusting for the effect of shares held in trust) at the end of the respective financial years:

2006 2005

Net assets (as adjusted) (£ million) 5,100.9 3,901.4

Number of ordinary shares in issue at year end (as adjusted) (number of shares, million) 1,850.1 1,832.3

(c)

Capital expenditure by segment

Intangible assets Property, plant and equipment

2006 2005 2006 2005

Note £m £m £m £m

Continuing operations

United Kingdom

Energy Networks (i) 11.9 8.4 286.3 277.0

Energy Retail & Wholesale (i) 46.3 15.3 177.3 133.6

United Kingdom total 58.2 23.7 463.6 410.6

Continuing operations

United States

PPM Energy 2.6 3.5 423.8 56.3

United States total 2.6 3.5 423.8 56.3

Total continuing operations 60.8 27.2 887.4 466.9

Unallocated 2.6 2.6 19.3 8.0

Total (i) 63.4 29.8 906.7 474.9

(i) Capital expenditure on property, plant and equipment by business segment is stated gross of capital grants and customer contributions. Capital expenditure on property, plant and equipment for continuing operations net of capital grants and customer contributions amounted to £886.9 million (2005 £449.3 million). Capital grants and customer contributions receivable in respect of continuing operations during the year of £19.8 million (2005 £25.6 million) comprised Energy Networks £19.5 million (2005 £25.1 million) and Energy Retail & Wholesale £0.3 million (2005 £0.5 million).

100 ScottishPower Annual Report & Accounts 2005/06

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16 Intangible assets

Other intangible assets

(a) Year ended 31 March 2005 Note Goodwill £m Computer software £m Hydro relicensing £m Other £m Total £m Total £m

Cost:

At 1 April 2004 2,339.7 566.6 47.7 — 614.3 2,954.0

Additions — 43.7 20.6 — 64.3 64.3

Acquisitions (i) — — — 142.8 142.8 142.8

Disposals — (12.0) — — (12.0) (12.0)

Exchange (61.7) (6.9) (2.1) — (9.0) (70.7)

At 31 March 2005 2,278.0 591.4 66.2 142.8 800.4 3,078.4

Amortisation:

At 1 April 2004 483.8 305.7 2.1 — 307.8 791.6

Amortisation for the year — 61.3 1.7 34.4 97.4 97.4

Impairment 922.0 — — — — 922.0

Disposals — (10.9) — — (10.9) (10.9)

Exchange (12.9) (3.3) (0.1) — (3.4) (16.3)

At 31 March 2005 1,392.9 352.8 3.7 34.4 390.9 1,783.8

Net book value:

At 31 March 2005 885.1 238.6 62.5 108.4 409.5 1,294.6

At 1 April 2004 1,855.9 260.9 45.6 — 306.5 2,162.4

Year ended 31 March 2006 Notes Goodwill £m Computer software £m Hydro relicensing £m Other £m Total £m Total £m

Cost:

At 1 April 2005 2,278.0 591.4 66.2 142.8 800.4 3,078.4

Derecognised on implementation of IAS 39 (ii) — — — (142.8) (142.8) (142.8)

At 1 April 2005 – as restated 2,278.0 591.4 66.2 — 657.6 2,935.6

Discontinued operations – Additions for the period to 23 May 2005 — 2.0 0.8 — 2.8 2.8

Transferred to assets classified as held for sale on 24 May 2005 (iii) (2,170.4) (240.9) (67.0) — (307.9) (2,478.3)

107.6 352.5 — — 352.5 460.1

Continuing operations – Acquisition (iv) 8.0 — — — — 8.0

– Additions (v) — 44.5 — 18.9 63.4 63.4

— Disposals (v) — (2.9) — (4.1) (7.0) (7.0)

– Exchange 0.9 0.7 — — 0.7 1.6

At 31 March 2006 116.5 394.8 — 14.8 409.6 526.1

Amortisation:

At 1 April 2005 1,392.9 352.8 3.7 34.4 390.9 1,783.8

Derecognised on implementation of IAS 39 (ii) — — — (34.4) (34.4) (34.4)

At 1 April 2005 – as restated 1,392.9 352.8 3.7 — 356.5 1,749.4

Discontinued operations – Amortisation for the period to 23 May 2005 — 3.5 0.2 — 3.7 3.7

Transferred to assets classified as held for sale on 24 May 2005 (iii) (1,377.2) (124.2) (3.9) — (128.1) (1,505.3)

15.7 232.1 — — 232.1 247.8

Continuing operations – Amortisation for the year (vi) — 32.5 — — 32.5 32.5

– Disposals — (2.8) — — (2.8) (2.8)

– Exchange — 0.2 — — 0.2 0.2

At 31 March 2006 15.7 262.0 — — 262.0 277.7

Net book value:

At 31 March 2006 100.8 132.8 — 14.8 147.6 248.4

At 1 April 2005 885.1 238.6 62.5 108.4 409.5 1,294.6

(i) Other intangible assets acquired in the year ended 31 March 2005 represented in-the-money gas contracts acquired on the Damhead Creek and South Coast Power transactions. (ii) On the implementation of IAS 39 on 1 April 2005, in-the-money gas contracts acquired on the Damhead Creek and South Coast Power transactons were reclassified and remeasured as ‘Derivative financial instruments’.

(iii) On 24 May 2005, the intangible assets relating to the PacifiCorp disposal group were reclassified as ‘Assets classified as held for sale’ in accordance with IFRS 5. (iv) Goodwill of £8.0 million arose on the group’s acquisition of the remaining 50% of Core Utility Solutions Limited, which became a 100% subsidiary of the group. (v) Additions and disposals in the ‘Other’ category in the year ended 31 March 2006 are in respect of emissions allowances.

(vi) Amortisation of £8.1 million is included in ‘Cost of sales’ in the Group Income Statement; £12.5 million in ‘Transmission and distribution costs’ and £11.9 million in ‘Administrative expenses’.

(b)

Impairment tests for goodwill

Goodwill has been allocated for impairment testing purposes to three individual cash-generating units—Rye House power station, Katy gas storage facility and Core Utility Solutions Limited. The carrying amount of goodwill allocated to Rye House power station (£82.2 million) is significant in comparison with the total carrying amount of goodwill (£100.8 million). The recoverable amount of Rye House power station has been determined based on a value-in-use calculation. That calculation uses cash flow projections based on a financial business plan covering a ten-year period, and a discount rate of 13.5% pre-tax. A business plan covering a ten-year period has been used due to the long-term nature of the business. Cash flows beyond that period have been extrapolated using a steady 2.5% growth rate which results in no growth in real terms beyond the financial business plan period. The value-in-use calculation also takes into account the extrinsic value of the power station as calculated by a widely recognised option pricing model. The extrinsic value of the station represents the additional value of the station from the capture of short-term volatilities in the electricity, natural gas and carbon markets. Management believes that any reasonably possible change in the key assumptions on which Rye House’s recoverable amount is based would not cause Rye House’s carrying amount to exceed its recoverable amount.

Key assumptions used for value-in-use calculations

Growth rate (beyond period covered by business plan) – 2.5% nominal, 0% real

Discount rate (pre-tax) – 13.5%

Forward price of underlying commodities (used to calculate extrinsic value)

Volatility of underlying commodities (used to calculate extrinsic value)

Correlations of underlying commodities (used to calculate extrinsic value)

Basis for determining values assigned to key assumptions

Use of a 0% real growth rate is derived from past experience and future expectations

for the station

Discount rate is determined on the basis of market data and the divisional cost of capital

Market quotes/management future expectations

Market quotes/historical analysis

Historical analysis

ScottishPower Annual Report & Accounts 2005/06 101

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

17 Property, plant and equipment

Year ended 31 March 2005 Land and buildings £m Plant and machinery £m Vehicles and equipment £m Total £m

Cost:

At 1 April 2004 595.4 9,714.8 717.0 11,027.2

Additions 23.8 849.3 70.6 943.7

Acquisitions 13.1 439.1 – 452.2

Disposals (3.0) (92.7) (59.2) (154.9)

Exchange (4.5) (140.9) (13.2) (158.6)

At 31 March 2005 624.8 10,769.6 715.2 12,109.6

Depreciation:

At 1 April 2004 181.7 2,004.3 349.6 2,535.6

Charge for the year 16.6 296.6 84.5 397.7

Disposals (2.0) (76.4) (55.3) (133.7)

Exchange (0.6) (19.2) (5.1) (24.9)

At 31 March 2005 195.7 2,205.3 373.7 2,774.7

Net book value:

At 31 March 2005 429.1 8,564.3 341.5 9,334.9

At 1 April 2004 413.7 7,710.5 367.4 8,491.6

Year ended 31 March 2006 Notes Land and buildings £m Plant and machinery £m Vehicles and equipment £m Total £m

Cost:

At 1 April 2005 624.8 10,769.6 715.2 12,109.6

Discontinued operations – Additions for the period to 23 May 2005 4.5 70.0 7.7 82.2

– Disposals for the period to 23 May 2005 (4.7) (5.7) (1.5) (11.9)

Transferred to assets classified as held for sale on 24 May 2005 (a) (150.5) (4,881.2) (402.8) (5,434.5)

474.1 5,952.7 318.6 6,745.4

Continuing operations – Additions 11.6 846.8 48.3 906.7

– Acquisition – 1.2 – 1.2

– Disposals (3.3) (67.6) (31.4) (102.3)

– Exchange 0.3 45.9 6.1 52.3

At 31 March 2006 482.7 6,779.0 341.6 7,603.3

Depreciation:

At 1 April 2005 195.7 2,205.3 373.7 2,774.7

Discontinued operations – Charge for the period to 23 May 2005 0.4 22.1 5.9 28.4

– Disposals for the period to 23 May 2005 (0.1) (0.8) (0.4) (1.3)

Transferred to assets classified as held for sale on 24 May 2005 (a) (8.1) (662.7) (183.2) (854.0)

187.9 1,563.9 196.0 1,947.8

Continuing operations – Impairment 9 – 19.4 – 19.4

– Charge for the year 11.7 167.4 37.0 216.1

– Disposals (1.0) (50.7) (21.4) (73.1)

– Exchange 1.0 0.6 1.7 3.3

At 31 March 2006 199.6 1,700.6 213.3 2,113.5

Net book value:

At 31 March 2006 283.1 5,078.4 128.3 5,489.8

At 1 April 2005 429.1 8,564.3 341.5 9,334.9

Included in the cost of property, plant and equipment above are: Note 2006 £m 2005 £m

Assets in the course of construction 562.0 779.7

Other assets not subject to depreciation (b) 83.2 135.0

(a) On 24 May 2005, property, plant and equipment relating to the PacifiCorp disposal group was reclassified as ‘Assets classified as held for sale’ in accordance with IFRS 5. (b) Other assets not subject to depreciation are land. (c) Land and buildings held by the group are predominantly freehold. (d) Interest on the funding attributable to major capital projects was capitalised during the year at a rate of 5.5% (2005 6%) in the UK and at rates of 3.5% to 4.6% (2005 6%) in the US.

(e)

The cost of fully depreciated property, plant and equipment still in use was £615.1 million (2005 £553.1 million).

(f) The net book value of property, plant and equipment held under finance leases at 31 March 2006 was £90.3 million (2005 £97.3 million). The charge for depreciation against these assets during the year was £3.0 million (2005 £5.9 million).

(g) Included within other operating income in the income statement is £8.8 million (2005 £4.4 million) relating to compensation received from third parties for items of property, plant and equipment that were impaired, lost or given up.

(h)

Assets pledged as security for liabilities at 31 March 2006 amounted to £nil (2005 £6.9 million).

102 ScottishPower Annual Report & Accounts 2005/06

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18 Investments accounted for using the equity method

Jointly controlled entities Associates Shares £m Loans £m Shares £m Total £m

At 1 April 2004 23.5 38.8 2.7 65.0

Additions 18.3 1.5 – 19.8

Share of retained (loss)/profit (0.4) (1.8) 2.2 –

Disposals and other (2.3) (8.8) (0.9) (12.0)

Transfer of joint venture to a subsidiary – (19.1) – (19.1)

Exchange (0.6) – – (0.6)

At 31 March 2005 38.5 10.6 4.0 53.1

Additions 70.1 0.3 – 70.4

Share of retained profit/(loss) 6.2 (7.1) 0.3 (0.6)

Disposals and other (1.0) (0.4) (0.5) (1.9)

Exchange 5.7 – – 5.7

At 31 March 2006 119.5 3.4 3.8 126.7

Aggregated amounts relating to jointly controlled entities and associates are given below:

Jointly controlled entities Associates

2006 2005 2006 2005

£m £m £m £m

Income 13.1 27.4 1.2 1.2

Reversal of impairment – – – 2.1

Expenses (14.0) (29.6) (0.9) (1.1)

(Loss)/profit for the year (0.9) (2.2) 0.3 2.2

Non-current assets 148.4 62.8 2.7 3.1

Current assets 12.7 22.1 2.1 1.8

Total assets 161.1 84.9 4.8 4.9

Current liabilities (8.9) (7.4) (0.2) –

Non-current liabilities (32.7) (39.0) (0.8) (0.9)

Total liabilities (41.6) (46.4) (1.0) (0.9)

Net assets 119.5 38.5 3.8 4.0

The principal subsidiaries, jointly controlled entities and associates are listed on page 155.

19 Other investments

Notes Available- for-sale investments £m Other investments £m Total £m

At 1 April 2004 57.2 72.6 129.8

Additions 2.3 2.6 4.9

Disposals and other (8.7) (2.5) (11.2)

Exchange (2.0) (1.2) (3.2)

At 1 April 2005 48.8 71.5 120.3

Remeasurement adjustment on implementation of IAS 39 (a) (2.1) – (2.1)

At 1 April 2005 – as restated 46.7 71.5 118.2

Discontinued operations – Additions to 23 May 2005 – 1.3 1.3

– Transferred to assets classified as held for sale on 24 May 2005 (b) (46.7) (72.3) (119.0)

– 0.5 0.5

Continuing operations – Additions – 3.5 3.5

– Disposals – (0.1) (0.1)

– Exchange – 0.2 0.2

At 31 March 2006 (c) – 4.1 4.1

(a) On the implementation of IAS 39 on 1 April 2005, available-for-sale investments previously recorded at cost were restated to fair value. This resulted in a reduction in the carrying value of such investments by £2.1 million.

(b) On 24 May 2005, available-for-sale investments and other investments relating to the PacifiCorp disposal group were reclassified as ‘Assets classified as held for sale’ in accordance with IFRS 5.

(c) At 31 March 2006 the group held £4.1 million of investments for which no quoted market price is available and whose fair value could not be reliably measured. Those investments are held at cost.

ScottishPower Annual Report & Accounts 2005/06 103

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

20 Inventories

2006 £m 2005 £m

Raw materials and consumables 102.7 110.8

Fuel stocks 103.0 71.1

Work in progress 1.8 3.5

207.5 185.4

(a)

Inventories with a value of £2,790.6 million (2005 £2,199.4 million) were recognised as an expense during the year.

(b)

The value of inventories written down during the year was £nil (2005 £0.4 million).

21 Trade and other receivables

Note 2006 £m 2005 £m

(a)

Current receivables:

Trade receivables (i) 491.9 521.5

Prepayments and accrued income 786.1 668.9

Other debtors 166.3 485.1

1,444.3 1,675.5

(b)

Non-current receivables:

Other receivables 10.7 56.2

10.7 56.2

1,455.0 1,731.7

(i) Trade receivables are stated net of provisions for doubtful debts of £78.4 million (2005 £60.6 million) which has been estimated by management, taking into account future cash flows, based on prior experience and assessment of the current economic environment within which the group operates. (ii) The group enters into standard netting agreements with its commodity trading counterparties in order to mitigate the credit risk exposure of the business. In addition, the group utilises other forms of collateral to manage its credit risk exposure. These forms of collateral include margining for trading with exchanges, cash collateral utilised for bilateral and brokered trading as well as letters of credit. The total value of all such collateral held with respect to current receivables at the balance sheet date is £76.2 million. (iii) With the exception of retail customers, the group considers that 100% of its credit risk can be considered to be with counterparties in related energy industries or with financial institutions operating in energy markets.

(iv) Trading terms are governed by Industry Standard agreements which typically provide for interest to be charged where payments are not made on the specified settlement date.

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22 Finance lease receivables

2006 £m 2005 £m

Amounts receivable under finance leases:

Current receivables 20.5 17.3

Non-current receivables 104.6 158.4

125.1 175.7

2006 £m 2005 £m

Gross receivables from finance leases:

Within one year 28.4 31.8

Between one and five years 79.2 132.2

More than five years 63.6 91.9

171.2 255.9

Unearned future finance income on finance leases (46.1) (80.2)

Net investment in finance leases 125.1 175.7

The net investment in finance leases is analysed as follows:

Within one year 20.5 17.3

Between one and five years 53.0 88.7

More than five years 51.6 69.7

125.1 175.7

The group enters into finance leasing arrangements principally in respect of its US aircraft portfolio. The average lease term of finance leases entered into is 13 to 19 years. The net investment in finance leases at 31 March 2006 of £125.1 million is stated after provision for impairment of £25.4 million.

23 Financial assets

The group has taken exemption under IFRS 1 from applying the standards IAS 32 and IAS 39 in the comparative period. As a result, comparative information disclosed within this note has not been prepared in accordance with IFRS but in accordance with UK GAAP applicable in the comparative period.

At 31 March 2006

(a)

Categories of financial assets Notes UK £m US £m Total £m

Derivative financial assets (current and non-current):

Financial assets at fair value through the income statement (i) 376.7 136.1 512.8

Hedging derivatives (ii) 951.2 5.9 957.1

1,327.9 142.0 1,469.9

Cash and cash equivalents:

Held-to-maturity investments (iii) 241.4 – 241.4

Cash 65.6 141.2 206.8

Available-for-sale financial assets (iv) 3,136.2 – 3,136.2

3,443.2 141.2 3,584.4

Receivables (v) 1,174.7 226.4 1,401.1

Finance lease receivables (current and non-current) (vi) 3.9 121.2 125.1

Other investments 2.6 1.5 4.1

5,952.3 632.3 6,584.6

(i) Included within this category are instruments which, although classified as ‘fair value through the income statement’, have been transacted for risk mitigation purposes.

The fair value of those instruments is derived from quoted market prices, rates from third-party sources and other valuation methods. (ii) Further detail on hedging derivative instruments is disclosed in Note 25.

(iii) Held-to-maturity investments include non-derivative debt instruments with fixed and determinable payments and fixed maturity which the group intends to hold to maturity.

Those include fixed rate deposits. Those investments are accounted for at cost.

(iv) Included in the available-for-sale financial assets are money market fund deposits classified within the cash and cash equivalents line in the Group Balance Sheet. Available-for-sale financial assets are accounted for at fair value.

(v) Balances outwith the scope of IAS 32, principally prepayments, have been excluded. Receivables are accounted for at amortised cost.

(vi) Finance lease receivables are recorded in the balance sheet at the amount of the net investment in the lease after making any necessary impairment provisions for bad and doubtful rentals receivable.

ScottishPower Annual Report & Accounts 2005/06 105

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

23 Financial assets continued

(b) Terms of cash and cash equivalents and finance lease receivables Notes UK £m IFRS US £m At 31 March 2006 Total £m UK £m UK GAAP US £m At 31 March 2005 Total £m

Fixed rate financial assets (i) 245.3 121.2 366.5 3.9 84.2 88.1

Floating rate financial assets (ii) 3,201.8 141.2 3,343.0 1,524.0 234.4 1,758.4

3,447.1 262.4 3,709.5 1,527.9 318.6 1,846.5

All financial assets in the UK are denominated in pounds sterling and those in the US are denominated in US dollars.

(i) Included within fixed rate financial assets at 31 March 2006 are amounts receivable under finance leases of £125.1 million. Included within fixed rate financial assets at 31 March 2005 were amounts receivable under finance leases of £153.4 million less non-recourse finance of £65.3 million.

(ii) Included within floating rate financial assets of the group’s UK and US operations are cash deposits of which £nil in the UK and £nil in the US (2005 £2.3 million and £nil in the UK and US respectively) are subject to either a legal assignment or a charge in favour of a third party.

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

Based on the floating rate treasury financial assets of £3,343.0 million at 31 March 2006 (2005 £1,758.4 million), a 100 basis point change in interest rates would result in a £33.4 million change in profit before tax for the year (2005 £17.6 million).

None of the treasury assets above create potentially significant credit exposure on the basis that all counterparties are required to have a short-term rating of at least A-1, P-1 or F-1 from one of the three major rating agencies.

Weighted average interest rate at which financial assets are fixed Weighted average period for which interest is fixed

At 31 March 2006 At 31 March 2005 At 31 March 2006 At 31 March 2005

IFRS UK GAAP IFRS UK GAAP

UK US UK US UK US UK US

% % % % Years Years Years Years

Fixed rate financial assets 4.6 11.0 10.0 10.0 0.1 4 8 4

All amounts in the analysis above take into account the effect of interest rate swaps and currency swaps and the effect of price hedging. 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 floating rate financial assets as at 31 March 2006 were as follows: UK operations 4.5%, US operations 4.4% (2005 4.8% and 2.0% respectively).

At 31 March 2005, the group also had certain equity investments which have been excluded from the disclosures above because they had no maturity date. The book value of these investments was £48.8 million and the fair value was £46.9 million.

24 Financial liabilities

At 31 March 2006

(a)

Categories of financial liabilities Notes UK £m US £m Total £m

Derivative financial liabilities (current and non-current):

– Financial liabilities designated at fair value through the income statement (i) 392.5 142.6 535.1

– Hedging derivatives (ii) 41.2 – 41.2

433.7 142.6 576.3

Loans and other borrowings (current and non-current):

– unsecured (iii) 3,486.5 32.2 3,518.7

– secured (iii) – 83.7 83.7

3,486.5 115.9 3,602.4

Payables (iv) 1,004.0 274.2 1,278.2

Provisions (iv) 8.0 33.6 41.6

Obligations under finance leases (current and non-current) (v) – 64.7 64.7

4,932.2 631.0 5,563.2

(i) Included within this category are instruments which, although classified as ‘fair value through the income statement’, have been transacted for risk mitigation purposes.

(iii) Loans and other borrowings include non-derivative financial liabilities, other than liabilities relating to own use commodity purchases and settled commodity derivatives, which have been accounted for as part of payables. Loans and other borrowings are accounted for at amortised cost. Refer to Note 24(c) for further analysis.

(iv) Balances outwith the scope of IAS 32, principally payments received on account and other amounts not contractually committed, have been excluded. The fair value of payables disclosed above are not materially different from their book values.

(v) Obligation under finance leases comprises the fixed rate non-recourse debt in relation to the US lease portfolio. Maturity analysis is given in Note 27.

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24 Financial liabilities continued

At 31 March 2006

(b) Maturity analysis of loans and other borrowings IFRS Book value £m Fair value £m 2005 UK GAAP* Book value £m

UK operations

Within one year, or on demand 488.6 656.1

Between one and two years 25.8 25.8

Between two and three years 410.7 420.9

Between three and four years 635.8 642.8

Between four and five years 50.0 51.8

More than five years 1,875.6 2,058.4

3,486.5 3,855.8

US operations

Within one year, or on demand 34.4 34.4

Between one and two years 2.4 2.4

Between two and three years 2.5 2.5

Between three and four years 2.7 2.7

Between four and five years 2.9 2.9

More than five years 71.0 71.0

115.9 115.9

Total

Within one year, or on demand 523.0 690.5 553.4

Between one and two years 28.2 28.2 213.9

Between two and three years 413.2 423.4 90.1

Between three and four years 638.5 645.5 611.7

Between four and five years 52.9 54.7 1,047.0

More than five years 1,946.6 2,129.4 3,378.7

3,602.4 3,971.7 5,894.8

Finance leases included within each of the repayment categories listed above for the year ended 31 March 2005 are as follows: within one year or on demand £nil, between one and two years £0.2 million, between two and three years £0.3 million, between three and four years £0.3 million, between four and five years £0.5 million and in more than five years £12.7 million.

The minimum future finance lease payments for the year ended 31 March 2005 are detailed as follows: within one year or on demand £1.7 million, between one and two years £1.8 million, between two and three years £1.9 million, between three and four years £1.9 million, between four and five years £2.0 million and in more than five years £22.7 million. These payments include interest charges allocated to future years of £18.0 million.

As disclosed in Note 20(c) to the group’s Annual Report & Accounts 2004/05.

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

24 Financial liabilities continued

(c)

Analysis of loans and other borrowings by instrument and maturity

2006 IFRS 2005 UK GAAP Book value*

Weighted average interest rate Book value Total Fair value

2007 2008 2009 2010 2011 Thereafter

Analysis by instrument and maturity Notes 2006 2005* £m £m £m £m £m £m £m £m £m

Unsecured debt of UK operations

Uncommitted bank loans (i) 4.7% 4.2% 7.1 — — — — — 7.1 7.1 7.2

Medium-term notes/private placements (ii) 5.7% 5.8% 100.0 25.8 102.2 21.2 — 612.9 862.1 955.1 963.6

Loan notes 4.8% 4.8% — — — — — — — — 1.1

European Investment Bank loans (iii) 5.8% 5.9% — — 50.2 98.0 50.0 — 198.2 202.4 199.2

Variable rate Australian dollar bond 2011 (iv) 5.3% 5.4% — — — — — 262.2 262.2 274.2 235.1

4.000% US dollar convertible bonds (v) 4.4% 4.4% 381.5 — — — — — 381.5 548.7 365.4

5.250% deutschmark bond 2008 (vi) 6.8% 6.8% — — 258.3 — — — 258.3 268.0 246.1

6.625% euro-sterling bond 2010 (vii) 6.7% 6.7% — — — 200.9 — — 200.9 211.2 198.8

4.910% US dollar bond 2010 (viii) 5.0% 5.0% — — — 315.7 — — 315.7 309.8 289.9

5.375% US dollar bond 2015 (viii) 5.1% 5.1% — — — — — 344.2 344.2 335.7 325.1

8.375% euro-sterling bond 2017 (vii) 8.5% 8.5% — — — — — 204.9 204.9 252.7 198.0

6.750% euro-sterling bond 2023 (vii) 6.8% 6.8% — — — — — 251.6 251.6 296.5 247.3

5.810% US dollar bond 2025 (viii) 5.9% 5.9% — — — — — 199.8 199.8 194.4 183.5

488.6 25.8 410.7 635.8 50.0 1,875.6 3,486.5 3,855.8 3,460.3

Unsecured debt of US operations

Bank overdrafts (i) — — 1.4 — — — — — 1.4 1.4 20.5

Commercial paper (ix) — 2.9% — — — — — — — — 248.0

Pollution control revenue bonds (x) — 2.5% — — — — — — — — 178.7

Finance leases (xi) — 11.9% — — — — — — — — 14.0

Other borrowings (xii) 4.4% 2.9% 30.8 — — — — — 30.8 30.8 9.8

32.2 — — — — — 32.2 32.2 471.0

Unsecured debt 520.8 25.8 410.7 635.8 50.0 1,875.6 3,518.7 3,888.0 3,931.3

Secured debt of US operations

First mortgage and collateral bonds (xiii) — 7.0% — — — — — — — — 1,636.5

Pollution control revenue bonds (x) — 3.3% — — — — — — — — 209.7

Other secured borrowings (xiv) 7.1% 6.9% 2.2 2.4 2.5 2.7 2.9 71.0 83.7 83.7 117.3

Secured debt 2.2 2.4 2.5 2.7 2.9 71.0 83.7 83.7 1,963.5

Total debt 523.0 28.2 413.2 638.5 52.9 1,946.6 3,602.4 3,971.7 5,894.8

As disclosed in Note 20(a) to the group’s Annual Report & Accounts 2004/05.

Weighted average interest rates in the analysis above take into account the effect of interest rate swaps and currency swaps used to convert underlying debt into sterling and the effect of price hedging.

(i)

Bank overdrafts and uncommitted short-term borrowings

For short-term borrowings (overdrafts and uncommitted bank loans) the book value approximates the fair value because of their short maturities.

(ii) Medium-term notes/private placements

Scottish Power plc and Scottish Power UK plc have an established joint US$7.0 billion euro-medium-term note programme. Scottish Power plc has not yet issued under the programme. Paper is issued in a range of currencies and swapped back into sterling. As at 31 March 2006, maturities range from 1 to 34 years. The fair value of those medium-term loans/placements as at 31 March 2006 has been calculated as £955.1 million. The fair value has been calculated by discounting the estimated cash flows at the appropriate market discount rate.

Some of those notes (total value of £300.0 million) contain a “Loss of licences” covenant that will require repayment of the outstanding amount should the UK group lose all of its electricity licences (distribution, transmission and supply licences). The notes can be redeemed by the group with 30 to 90 days’ notice in case of unfavourable and unavoidable change in the UK tax laws impacting on the note payments.

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

These loans incorporate agreements with various interest rates and maturity dates. The maturity dates of these arrangements range from 2009 to 2011. The fair values of the European Investment Bank loans at 31 March 2006 have been calculated by discounting their future cashflows at market rates adjusted to reflect the redemption adjustments allowed under each agreement.

(iv) Variable rate Australian dollar bond 2011

The bond has been issued by Scottish Power UK plc. The bond’s fair value at 31 March 2006 has been estimated using quoted market prices converted at the spot rate of exchange as appropriate. The bond contains a “Loss of licences” covenant that will require repayment of the entire debt should the UK group lose all of its electricity licences (distribution, transmission and supply licences). The bond contains an early redemption option where the group can choose to repay the principal amount and accrued interest at any time by giving 30 to 90 days’ notice to the lender.

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24 Financial liabilities continued

(v)

US dollar convertible bonds

Scottish Power Finance (Jersey) Limited (“the issuer”) has issued US$700 million 4% step-up perpetual subordinated convertible bonds guaranteed by Scottish Power plc. The bonds are convertible into redeemable preference shares of the issuer which will be exchangeable immediately on issuance for ordinary shares in Scottish Power plc. The Exchange Price was initially set at £4.60 but will be subject to change on the occurrence of certain events set out in the Offering Circular, including payments of dividends greater than amounts set out in the bond agreement, capital restructuring and change of control. Subsequent to 31 March 2006 and, as a result of the return of cash to shareholders, the Exchange Price has been adjusted to £4.544. The exchange rate to be used to convert US dollar denominated preference shares into sterling is 1.6776. Conversion of the bonds into shares is at the option of the bondholders. During the period up to 3 July 2011, they can opt to convert the bonds into preference shares of the issuer which are immediately exchangeable into ordinary shares of Scottish Power plc. If the bonds remain outstanding after 10 July 2011, they will bear interest at the rate of 4% per annum above the London Interbank Offer Rate for three month US dollar deposits. The bonds are perpetual, so there is no fixed redemption date. There are, however, occasions where redemption may occur. The issuer may redeem the bonds: i) if, after 10 July 2009, for the preceding 30 dealing days the average of the middle market quotations of any ordinary share has been at least 130% of the average Exchange Price; ii) if, at any time, conversion rights have been exercised and/or purchases effected in respect of 85% or more in principal amount of the bonds; or iii) at any time after 10 July 2011, provided all the outstanding bonds are redeemed. Under ii) and iii), the redemption amount will be principal value plus accrued, unpaid interest. Under i), the redemption will be by way of issue of shares. The bondholders may require redemption if an offer is made to the shareholders of Scottish Power plc to buy their shares in the company. The redemption amount will be principal value plus accrued, unpaid interest. The fair value of the liability component of these bonds has been estimated by discounting the related future cash flows at a market rate. The derivative component relating to the conversion option of this bond has been valued and is accounted for within Derivative Financial Instruments on the balance sheet. The bond also contains a “Loss of licences” covenant that will require repayment of the entire debt should the UK group lose all of its electricity licences (distribution, transmission and supply licences).

In the light of evolving practice, the group has changed the classification of its convertible bonds from Non-current liabilities to Current liabilities and restated comparative figures accordingly. The bonds are perpetual and have no fixed redemption date; although they can be redeemed in limited circumstances. Bondholders can convert into ordinary shares of Scottish Power plc at any time and, therefore, the bonds meet the definition of current liabilities in IAS 1 ‘Presentation of Financial Statements’ and the IASB’s Framework for the Preparation and Presentation of Financial Statements.

(vi) Deutschmark bond

The bond has been issued by Scottish Power UK plc. The bond’s fair value at 31 March 2006 has been estimated using quoted market prices converted at the spot rate of exchange as appropriate. The bond also contains a “Loss of licences” covenant that will require repayment of the entire debt should the UK group lose all of its electricity licences (distribution, transmission and supply licences). The bond contains an early redemption option where the group can repay it with 30 to 90 days’ notice in case of unfavourable and unavoidable change in the UK tax laws impacting on the bond payments.

(vii) Euro-sterling bonds

These are quoted euro bonds with various maturities. Their fair values at 31 March 2006 are based on their quoted closing clean market price converted at the spot rate of exchange as appropriate. The bonds also contain a “Loss of licences” covenant that will require repayment of the entire debt should the UK group lose all of its electricity licences (distribution, transmission and supply licences). The bonds also contain early redemption options where the group can repay them with 30 to 90 days’ notice in case of an unfavourable and unavoidable change in the UK tax laws impacting on the bond payments. The sterling bond due 2017 can also be redeemed at any time by the group at the higher of principal amount or Redemption Price (as determined by Midland Bank plc) on giving 30 to 90 days’ notice to the lender. In a similar way the sterling bond due 2023 can be redeemed on giving 30 to 45 days’ notice at the higher of principal amount or Redemption Price.

(viii) US dollar 4.0 billion US shelf registration

In March 2005, Scottish Power plc established a US$4.0 billion US shelf registration for the issuance of debt and other securities. An inaugural issue of $1.5 billion of bonds was made during March 2005. These bonds were split into three maturities of 5, 10 and 20 years, with respective notional values being $550 million, $600 million and $350 million. The bonds’ fair value at 31 March 2006 has been estimated using quoted market prices converted at the spot rate of exchange as appropriate.

(ix) Commercial paper

Scottish Power UK plc has an established US$2.0 billion (2005 US$2.0 billion) euro-commercial paper programme. Paper was issued in a range of currencies and swapped back into sterling. As at 31 March 2005, PacifiCorp had a $1.5 billion domestic commercial paper programme. No issues are outstanding under the Scottish Power UK plc programme or have been made under this programme since April 2002. As at 31 March 2005, PacifiCorp had borrowings of £248.0 million under its commercial paper programme.

Amounts borrowed under commercial paper programmes are repayable in less than one year. There was no commercial paper outstanding as at 31 March 2006.

(x)

Pollution control revenue bonds

These were bonds issued by qualified tax exempt entities to finance, or refinance, the cost of certain pollution control, solid waste disposal and sewage facilities. As at 31 March 2005, PacifiCorp had 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 was not subject to federal income taxation for most bondholders. In some cases, PacifiCorp issued first mortgage and collateral bonds as collateral for repayment.

(xi) Finance leases

These are facility leases that were accounted for as capital leases, maturity dates range from 2014 to 2022.

(xii) Other unsecured borrowings

The book value of other unsecured borrowings equates to their fair value because of their short maturities.

(xiii) First mortgage and collateral bonds

First mortgage and collateral bonds of PacifiCorp may be issued in amounts limited by its Domestic Electric operation’s property, earnings and other provisions of the mortgage indenture. A floating charge at 31 March 2005 over approximately US$13.1 billion of the eligible assets (based on original costs) of PacifiCorp was used as collateral for PacifiCorp’s first mortgage and collateral trust bonds.

(xiv) Other secured borrowings

Included within other secured borrowings is ScottishPower’s share of debt in a joint arrangement for the Klamath Co-Generation plant. The borrowings of the joint arrangement are the subject of a guarantee, for US$60.0 million, provided by Scottish Power Holdings Inc. (formerly PacifiCorp Holdings Inc.) in respect of second lien revenue bonds. The fair value of those borrowings is £83.7 million.

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for the year ended 31 March 2006

24 Financial liabilities continued

Maturity horizons by currency of loans and other borrowings 2007 £m 2008 £m 2009 £m 2010 £m 2011 £m Thereafter £m Total £m Fair value £m

Fixed rate (GBP) 100.0 25.8 55.0 249.0 50.0 809.7 1,289.5 1,447.9

Weighted average interest rate (GBP) 6.5% 6.7% 5.5% 6.5% 5.8% 6.4% 6.4%

Fixed rate (USD)—UK group 381.5 — — 315.7 — 596.9 1,294.1 1,444.1

Weighted average interest rate (USD)—UK group 4.0% — — 5.0% — 5.5% 4.9%

Fixed rate (USD)—US group 2.2 2.4 2.5 2.7 2.9 71.0 83.7 83.7

Weighted average interest rate (USD)—US group 7.1% 7.1% 7.1% 7.1% 7.1% 7.1% 7.1%

Fixed rate (EUR) — — 299.1 — — — 299.1 308.9

Weighted average interest rate (EUR) — — 5.2% — — — 5.2%

Index-linked (GBP) — — — — — 206.8 206.8 245.8

Weighted average interest rate (GBP) — — — — — RPI+3.5% RPI+3.5%

Variable rate (GBP) 7.1 — 30.0 57.0 — — 94.1 94.1

Weighted average interest rate (GBP) 2m LIBOR — 6m LIBOR 3m LIBOR — — 4m LIBOR

Variable rate (USD)—UK group — — 20.2 — — — 20.2 20.1

Weighted average interest rate (USD)—UK group — — 3m $LIBOR — — — 3m $LIBOR

Variable rate (USD)—US group 32.2 — — — — — 32.2 32.2

Weighted average interest rate (USD)—US group 1m LIBOR — — — — — 1m LIBOR

Variable rate (AUD) — — — — — 262.2 262.2 274.2

Weighted average interest rate (AUD) — — — — — 3m BBSW 3m BBSW

Variable rate (EUR) — — 6.4 14.1 — — 20.5 20.7

Weighted average interest rate (EUR) — — 3m LIBOR 6m LIBOR — — 5m LIBOR

Total debt 523.0 28.2 413.2 638.5 52.9 1,946.6 3,602.4 3,971.7

The disclosures represent the interest profile and currency profile of financial liabilities before the impact of derivative hedging instruments.

The average variable rates above, LIBOR, exclude margins. LIBOR is the Sterling London Inter Bank Offer Rate. $LIBOR is the US dollar London Inter Bank Offer Rate. GBP—Pounds Sterling, USD—American Dollars, CAD—Canadian Dollars, DKK—Danish Krone, EUR—Euros, JPY—Japanese Yen, AUD—Australian Dollars. BBSW is the Australian Bank Bill Rate.

Reference to “m” in “m LIBOR” represents months.

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24 Financial liabilities continued

At 31 March 2006 IFRS At 31 March 2005 UK GAAP

GBP USD Total GBP USD Total

(d)

Interest rate analysis of loans and other borrowings Note £m £m £m £m £m £m

Fixed rate borrowings 1,487.7 665.0 2,152.7 1,285.4 2,995.1 4,280.5

Floating rate borrowings (i) 1,417.5 32.2 1,449.7 1,010.9 603.4 1,614.3

2,905.2 697.2 3,602.4 2,296.3 3,598.5 5,894.8

(i) Based on the floating rate treasury debt of £1,449.7 million at 31 March 2006 (2005 £1,614.3 million), a 100 basis point change in interest rates would result in a £14.5 million change in profit before tax for the year (2005 £16.1 million).

Weighted average interest rate at which borrowings are fixed/capped Weighted average period for which interest is fixed/capped

At 31 March 2006 IFRS At 31 March 2005 UK GAAP At 31 March 2006 IFRS At 31 March 2005 UK GAAP

GBP USD GBP USD GBP USD GBP USD

% % % % Years Years Years Years

Fixed rate borrowings 5.6 4.6 6.7 6.1 6 8 10 10

All amounts in the analysis above take into account the effect of interest rate swaps and currency swaps used to convert underlying debt into sterling. This does not include currency swaps used as part of the hedging of the US net investment. 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 rate on short-term borrowings as at 31 March 2006 were as follows: GBP 4.7%, USD 4.8% (2005 4.7% and 2.9% respectively).

(e)

Borrowing facilities

The group has the following undrawn committed borrowing facilities at 31 March 2006 in respect of which all conditions precedent have been met. The facility was renegotiated on 20 December 2005. All facilities are floating rate facilities. The ability to draw on these facilities is governed by certain covenants relating to the performance of the group relative to its interest and dividend payments as well as the group’s gearing. None of these covenants have been breached in the course of the year or at the year end.

At 31 March 2006 IFRS £m At 31 March 2005 UK GAAP £m

Expiring between two and five years 500.0 952.4

Commitment fees on the above facilities were as follows: UK Operations £1.7 million (2005 £1.8 million); US Operations £nil (2005 £0.6 million).

(f)

Fair value of financial instruments

Information required under UK GAAP for the year ended 31 March 2005 relating to the fair value of financial instruments is set out below.

At 31 March 2005 UK GAAP

Book amount £m Fair value £m

Short-term debt and current portion of long-term debt 547.1 547.1

Long-term debt 5,376.3 5,818.4

Cross-currency swaps (28.6) (44.9)

Total debt 5,894.8 6,320.6

Interest rate swaps (4.1) (31.7)

Interest rate swaptions 2.6 1.5

Forward contracts (46.4) (81.0)

Net investment forward contracts (39.9) (28.1)

Net investment cross-currency swaps (80.3) (76.5)

Energy hedge contracts – (31.8)

Energy trading contracts (5.7) (5.7)

Total financial instruments 5,721.0 6,067.3

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for the year ended 31 March 2006

24 Financial liabilities continued

The assumptions used to estimate fair values of financial instruments at 31 March 2005 are summarised below:

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

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

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

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

(v) The fair values of the sterling interest rate swaps and sterling forward rate agreements 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 2005.

(vii) The fair values of the cross-currency 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 2005.

(ix) The fair values of electricity and gas forwards and futures are estimated using market forward commodity price curves as at 31 March 2005.

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

(g)

Fair value of financial assets and liabilities held for trading

Information required under UK GAAP for the year ended 31 March 2005 relating to the fair value of financial assets and liabilities held for trading is set out below.

2005

UK GAAP

£m

Net realised and unrealised gains included in profit and loss account 10.5

Fair value of financial assets held for trading at 31 March 2005 33.1

Fair value of financial liabilities held for trading at 31 March 2005 (27.4)

In the UK and US a limited amount of proprietary trading within the limits and guidelines of the risk management framework is undertaken. The transactions included in the table above consist of forward purchase and sale contracts of electricity and forward purchase and sale contracts of gas and gas futures contracts. These contracts were marked to market value using externally derived market prices and any gain or loss arising was recognised in the profit and loss account.

(h)

Currency exposures

Information required under UK GAAP for the year ended 31 March 2005 relating to currency exposure is set out below.

The group uses forward contracts, cross-currency interest rate swaps and borrowings in foreign currencies to mitigate the currency exposures arising from its net investments overseas. Gains and losses arising on net investments overseas and the forward contracts, cross-currency interest rate swaps and foreign currency borrowings used to hedge the currency exposures are recognised in the Statement of Recognised Income and Expense. Other than the transactions referred to above, the group did not hold material net monetary assets or liabilities in currencies other than functional currency at 31 March 2005.

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25 Hedging and derivative instruments

Hedging activities are undertaken by the group to manage risk exposure in three main areas: Energy Market Risk, Credit Risk and Treasury Management.

Energy Market Risk

The group is exposed to market risk associated with fluctuations in the market price of electricity and generation fuel compounded by volumetric risk caused by unplanned changes in the load and output of its portfolio of generation assets. The risk management policies are implemented at the business level with the oversight of the businesses’ Risk Management committees. The businesses which are exposed to and therefore undertake activities to manage energy market risk are Energy Retail & Wholesale and PPM Energy.

Energy Retail & Wholesale

Energy Retail & Wholesale’s hedging activities associated with energy market risk are undertaken within the Energy Wholesale function. The strategy of the business is to mitigate the economic risks associated with electricity generation, purchase of fuel and supply of electricity and natural gas to end users in both the wholesale and retail markets and also to optimise the value of the asset portfolio. From a reporting perspective the objective is to report earnings results that are consistent with its operational strategies and hence recognise the earnings effect of financial and non-financial derivative transactions executed to hedge economic business risks in the same period in which the hedged operational activity impacts earnings. The aim is to minimise earnings volatility, which would otherwise be present as a result of fair valuing all derivative contracts under IAS 39. To achieve this objective, where effectiveness documentation and reporting requirements are met, cash flow hedge accounting is applied by designation of a series of derivative trades and deferring in equity the fair value changes of open derivative positions until the period in which forecast transactions occur. A number of contracts do not qualify for own use or hedge accounting under IAS 39 and are therefore wholly or partially fair valued through the income statement.

Cash flow hedging strategies are developed for each of the electricity, natural gas and coal portfolios to hedge the variability in cash flows associated with changes in the market price of each commodity. Forward (fixed price/fixed volume) contracts are designated as hedging instruments in the power and gas hedges, and financial swaps are designated in the coal hedge.

The electricity hedge is in relation to a long-term electricity procurement contract where volumes purchased are based on floating prices, thereby exposing the business to cash flow variability. The cash flows on this contract are expected to occur until March 2011.

The gas and coal hedges relate to the cash flow variability associated with purchases of natural gas and coal at floating prices that are required to meet forecast demand for each commodity. Forecast demand is based on existing customer numbers and historic profiles of demand at levels that are highly probable of occurring. The associated cash flows extend until December 2010 for gas and December 2008 for coal.

The assessment of effectiveness of all hedging relationships currently in place is carried out on a monthly basis as part of the financial reporting cycle. Prospective assessment is carried out at inception of the hedge and on an ongoing basis to verify that the forecast is still highly probable of occurring. Retrospective assessment is also carried out to assess the effectiveness in the period under review. Prospective and retrospective assessment is performed using statistical analysis and the business can apply the hedge accounting rules prescribed by IAS 39 if the hedging relationship passes the criteria of a three-step regression test.

Hedge effectiveness is measured and respective entries recorded in the balance sheet, reserves and income statement on a monthly basis.

PPM Energy

PPM Energy undertakes hedging activities to mitigate the economic risks associated with the purchase, transportation, and storage of natural gas. The instruments utilised for economic hedging include:

– Fixed price financial basis and index swaps for natural gas

– European-style call and put options for natural gas and electricity

– American-style call and put options for natural gas

– Forward fixed price electricity contracts

Under IAS 39 the business has designated cash flow hedges to manage the variability of cash flows resulting from changes in the market price of gas for quantities of natural gas injected (purchased) and withdrawn (sold) from storage and to reduce volatility of earnings. PPM Energy designates forward gas purchase and sale contracts into the gas storage hedging portfolio. The actual injections and withdrawals of gas from storage occur continuously and the associated cash flows occur on a monthly basis.

Hedge effectiveness is measured and respective entries recorded in the balance sheet, reserves and income statement on a monthly basis.

Credit Risk

The group is exposed to both settlement risk (defined as the risk of a counterparty failing to pay for energy and/or services which have been delivered), as well as replacement risk (defined as the risk of incurring additional costs in order to replace a sale or purchase contract following a counterparty default). Credit risk is mitigated by contracting with multiple counterparties and limiting exposure to individual counterparties to clearly defined limits based upon the risk of counterparty default.

Aggregated portfolio risk is monitored and reported by credit risk indices simulations to quantify the value at risk within the existing portfolio.

With the exception of retail customers, the group considers that 100% of its credit risk can be considered to be with counterparties in related energy industries or with financial institutions operating in energy markets. At the counterparty level the group employs specific eligibility criteria in determining appropriate limits for each prospective counterparty and supplements this with netting and collateral agreements including margining, guarantees, letters of credit and cash deposits where appropriate. Counterparty exposures are then monitored on a daily basis.

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for the year ended 31 March 2006

25 Hedging and derivative instruments continued

Treasury Management

Within the Treasury function the group utilises a number of financial instruments to manage interest rate, foreign currency and value of net investment exposures. The following hedging strategies are currently in place:

Cash flow hedges

Hedging of forecasted interest payments on debt instruments issued by the group: Currently the interest payable on a loan with the European Investment Bank is being hedged to protect the group from variability of cash flows resulting from changes in the interest rates to which the payments are linked. Those payments are designated in a cash flow hedging relationship and are expected to occur quarterly up to the maturity of the loan in 2010. An interest rate swap has been designated as a hedging derivative instrument. Hedging of forecast interest payments on debt instruments denominated in foreign currencies: The group utilises loans denominated in EUR and in USD. Details on those loans are disclosed in Note 24. The interest payments which the group makes on those debts are subject to cash flow risk arising from changes in the EUR and USD exchange rates. Payments are occurring on a quarterly or semi-annual basis up to the maturities of the loans, which extend to 2008. The group has designated cross-currency interest rate swaps as hedges to those interest and principal payments.

Hedging of asset purchases: The group is subject to cash flow risk relating to the value of forecast purchases of various assets (such as coal and wind turbines) which are denominated in foreign currencies. The risk being hedged relates to changes in the foreign exchange rate of the forecast purchase price. The group enters into forward foreign exchange rate contracts to hedge those risks.

Fair value hedges

Hedging the value of issued sterling debt: The group has issued a number of medium-term loan notes at fixed interest rates. Those have been designated in a hedging relationship with floating for fixed rate swaps as the hedging derivatives. The objective of this hedging strategy is to protect the value of the group’s fixed loan notes from changes as a result of fluctuations of the market interest rates.

Hedging the value of cross currency debt: The group has issued debt instruments denominated in EUR, JPY, USD and AUD. The value of the group’s liability with respect to those instruments is subject to foreign exchange risk and interest rate risk. As a result the group has entered into cross-currency swaps as hedges and has designated those within a fair value hedging relationship.

Net investment hedges

ScottishPower hedges a proportion of the value of its net investments in its US operations. The risk being hedged is risk of changes in the value of the share of net assets in those operations due to fluctuations of the USD exchange rate. The instruments designated as hedges in the net investment portfolio are cross-currency interest rate swaps, forward USD contracts as well as debt issued in USD.

Other hedging strategies

Hedge assessment for all of the treasury hedging relationships currently in place is done on a quarterly basis. Assessment is done prospectively to verify that the forecast transactions are still highly probable of occurring (for cash flow hedges) as well as retrospectively, to assess the effectiveness in the period under review. Retrospective assessment is performed using the dollar offset approach which compares the change in fair value of the hedging instrument within the hedged item. The changes in fair value of the hedging derivative instruments are compared to the changes in fair value of the hedged items to assess whether a high level of correlation exists between those changes. An effectiveness test result between 80 and 125% means that the group can apply the hedge accounting rules prescribed by IAS 39.

Hedge effectiveness is measured and respective entries recorded in the balance sheet, reserves and income statement on a quarterly basis.

Treasury instruments are valued using quoted market prices only. Swaps and forward agreements are valued against the appropriate market-based curves. Forward price curves are developed using market prices from independent sources for liquid markets and products. No illiquid markets or products are used.

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25 Hedging and derivative instruments continued

Analysis of the derivative financial instruments disclosed on the balance sheet is shown below.

(a)

Analysis of derivative financial instruments Notes Assets Liabilities Total 2006 £m

Amounts falling due after more than one year:

Treasury derivatives 82.6 (38.6) 44.0

Derivative commodity contracts (i) 519.8 (111.1) 408.7

602.4 (149.7) 452.7

Amounts falling due within one year:

Treasury derivatives 41.1 (192.7) (151.6)

Derivative commodity contracts (i) 826.4 (233.9) 592.5

867.5 (426.6) 440.9

(ii) 1,469.9 (576.3) 893.6

This is analysed by derivative type as follows:

Fair value of commodity market risk hedging instruments (b) 820.1

Fair value of treasury risk hedging instruments (c) 95.8

Fair value of other commodity derivative contracts and embedded derivatives (d) 181.1

Other treasury derivative contracts (e) (203.4)

893.6

(i) These include derivative commodity contracts which are measured at fair value through the income statement as well as derivative contracts designated in hedging relationships.

(ii) Tables (b) to (e) analyse each of these categories by type and maturity profile.

(b) Fair value of commodity market risk hedging instruments Notes 2007 £m 2008 £m 2009 £m 2010 £m 2011 £m Thereafter £m Total £m

Cash flow hedges:

UK operations

Commodity hedges (i) 492.2 184.0 105.3 30.4 2.3 — 814.2

US operations

Hedging of injections and withdrawals of gas from storage

Forward gas sales and purchases and financial contracts (ii) 5.9 — — — — — 5.9

Total 498.1 184.0 105.3 30.4 2.3 — 820.1

Derivatives which have a positive fair value are shown in the table above without brackets.

(i) The fair value of derivative contracts in hedge relationships is determined using published market prices where available and, for illiquid periods, the forward price curves are derived from modelling techniques, which take into account market expectations and information available to all knowledgeable market participants.

(ii) The fair value of forward gas sales and purchases and financial contracts is determined using quoted market prices.

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for the year ended 31 March 2006

25 Hedging and derivative instruments continued

Interest rate swaps (i)

Variable to fixed (GBP) — — — (2.8) — — (2.8)

Weighted average pay rate — — — 6.3% — — 6.3%

Weighted average receive rate — — — 3m LIBOR — — 3m LIBOR

Fixed to variable (GBP) 3.8 0.8 — 7.7 — 10.9 23.2

Weighted average pay rate 6m LIBOR 6m LIBOR – 6m LIBOR – 6m LIBOR 6m LIBOR

Weighted average receive rate 6.5% 6.7% — 6.7% — 8.0% 7.3%

Cross-currency swaps (ii)

Receive fixed USD pay variable GBP — — — — — 1.7 1.7

Weighted average pay rate (GBP) — — — — — 6m LIBOR 6m LIBOR

Weighted average receive rate (USD) — — — — — 4.6% 4.6%

Receive variable USD pay fixed GBP — — (1.2) — — — (1.2)

Weighted average pay rate (GBP) — — 4.9% — — — 4.9%

Weighted average receive rate (USD) — — 3m LIBOR — — — 3m LIBOR

Receive variable AUD pay variable GBP — — — — — 32.4 32.4

Weighted average pay rate (GBP) — — — — — 6m LIBOR 6m LIBOR

Weighted average receive rate (AUD) — — — — — 3m BBSW 3m BBSW

Receive fixed EUR pay fixed GBP — — 10.1 — — — 10.1

Weighted average pay rate (GBP) — — 6.7% — — — 6.7%

Weighted average receive rate (EUR) — — 5.3% — — — 5.3%

Receive fixed EUR pay variable GBP — — 4.1 — — — 4.1

Weighted average pay rate (GBP) — — 6m LIBOR — — — 6m LIBOR

Weighted average receive rate (EUR) — — 5.0% — — — 5.0%

Receive variable EUR pay variable GBP — — 0.4 — — — 0.4

Weighted average pay rate (GBP) — — 6m LIBOR — — — 6m LIBOR

Weighted average receive rate (EUR) — — 3m LIBOR — — — 3m LIBOR

Receive variable EUR pay variable GBP — — — 1.4 — — 1.4

Weighted average pay rate (GBP) — — — 6m LIBOR — — 6m LIBOR

Weighted average receive rate (EUR) — — — 6m EURIBOR — — 6m EURIBOR

Receive fixed USD pay variable GBP — — — 0.7 — 0.1 0.8

Weighted average pay rate (GBP) — — — 4.6% — 4.9% 4.7%

Weighted average receive rate (USD) — — — 4.9% — 5.4% 5.0%

Forward contracts (iii)

Buy GBP, sell USD 27.6 10.1 — — — — 37.7

Buy USD, sell GBP (6.7) (6.0) — — — — (12.7)

Buy GBP, sell EUR — (0.2) — — — — (0.2)

Buy EUR, sell GBP 0.8 — — — — — 0.8

Buy DKK, sell GBP 0.1 — — — — — 0.1

Total 25.6 4.7 13.4 7.0 — 45.1 95.8

EURIBOR is the Euro European Inter Bank Offer Rate.

The abbreviations contained in the table are defined in Note 24(c). The above table includes derivatives relating to the partial hedging of the net assets of the US operations, hedging interest rate risk and foreign exchange risk on debt issues and hedging foreign exchange risk on a small number of business transactions.

Derivatives which have a positive fair value are shown in the table above without brackets, while derivatives with a negative fair value are shown as bracketed. (i) The fair values of the sterling interest rate swaps have been estimated by calculating the present value of estimated cash flows.

(ii) 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. (iii) The fair values of the forward contracts are estimated using quoted market forward exchange rates as at 31 March 2006.

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25 Hedging and derivative instruments continued

(d)

Fair value of other commodity derivative contracts and embedded derivatives

Notes 2007 £m 2008 £m 2009 £m 2010 £m 2011 £m Thereafter £m Total £m

Energy forwards and futures (i) (52.7) (1.2) (6.5) (6.0) (3.5) 0.1 (69.8)

Structured contracts (ii) 139.6 85.4 50.0 18.7 4.5 (19.1) 279.1

Other (iii) 7.5 (5.7) (5.4) (6.4) (4.4) (13.8) (28.2)

Total 94.4 78.5 38.1 6.3 (3.4) (32.8) 181.1

Listed above are contracts which are derivatives and do not qualify for own use exemption under IAS 39. Also included are embedded derivative elements in non-derivative commodity contracts accounted for on an accruals basis, which are required to be valued separately, as well as entire commodity contracts, including their derivative components, which have been fair valued due to the fact that embedded derivatives could not be separated. The fair values of the above derivative instruments have been calculated following the methods and assumptions outlined for the designated hedging instruments above, with the exception of the following other derivative contracts, which have been valued as indicated below.

(i) Included in this category are instruments which are held for trading and others which, although classified as fair value through the income statement, have been transacted for risk mitigation purposes. The fair value of those instruments is derived from published market prices from third party sources and other valuation techniques.

(ii) The fair value of structured, long-term commodity contracts is calculated using published market prices and other forecast prices which are based on models and other valuation methods.

(iii) Included within this category are other non-standard derivative contracts and embedded derivatives in own use commodity contracts which are required to be valued separately. Non-standard derivatives have been valued using published market prices from third party sources. Embedded derivatives in own use commodity contracts have been valued using the with and without approach. This means that the contract has been valued as a whole and also as a stand-alone contract excluding the derivative component. The difference between those two valuations has been determined to be the value of the derivative component.

(e)

Other treasury derivative contracts Notes 2007 £m 2008 £m 2009 £m 2010 £m 2011 £m Thereafter £m Total £m

Interest rate swaps

Fixed to index-linked (GBP) — — — — — (23.1) (23.1)

Weighted average pay rate — — — — — 3.35 x RPI 3.35 x RPI

Weighted average receive rate — — — — — 6.2% 6.2%

Fixed to variable (GBP) 1.0 — — — — — 1.0

Weighted average pay rate 6m LIBOR — — — — — 6m LIBOR

Weighted average receive rate 5.3% — — — — — 5.3%

Variable to fixed (GBP) — (0.8) — — — (1.8) (2.6)

Weighted average pay rate — 6.6% — — — 5.5% 5.8%

Weighted average receive rate — 6m LIBOR — — — 3m LIBOR 3m LIBOR

Variable to variable (GBP) — — 1.0 0.2 — — 1.2

Weighted average pay rate — — 6m LIBOR 6m LIBOR — — 6m LIBOR

Weighted average receive rate (i) — — CMS1 CMS2 — — CMS2

Swaptions

Variable to fixed (GBP) (ii) — — — — — (2.5) (2.5)

Weighted average pay rate — — — — — 4.3% 4.3%

Weighted average receive rate — — — — — 6m LIBOR 6m LIBOR

Forward contracts

Buy GBP, sell USD (0.5) 0.1 — — — — (0.4)

Buy USD, sell GBP 4.6 0.2 — — — — 4.8

Buy CAD, sell USD — 0.2 — — — — 0.2

Buy USD, sell CAD 0.5 — — — — — 0.5

Buy DKK, sell USD — 0.2 — — — — 0.2

Buy JPY, sell USD — 0.1 — — — — 0.1

Other contracts

Embedded derivative on convertible bonds (182.8) — — — — — (182.8)

Total (177.2) — 1.0 0.2 — (27.4) (203.4)

The fair values of the above derivative instruments have been calculated in accordance with the methods and assumptions outlined for the designated hedging instruments above, with the exception of the following other derivative contracts, which have been valued as indicated below.

The above derivative instruments represent derivative instruments that do not qualify for hedge accounting under IAS 39 and embedded derivatives.

(i) CMS1 – Interest received floats on a 10-year swap rate with a base minimum of 3.5%; CMS2 – interest received floats on 10-year swap rate. CMS refers to constant maturity swaps.

(ii) The fair values of the sterling interest rate swaptions are estimated using the sterling yield curve and implied volatilities as at 31 March 2006.

ScottishPower Annual Report & Accounts 2005/06 117

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

25 Hedging and derivative instruments continued

(f)

Total fair value of hedging and derivative contracts and embedded derivatives at 31 March 2006

Notes 2007 £m 2008 £m 2009 £m 2010 £m 2011 £m Thereafter £m Total £m

Energy Retail & Wholesale 587.9 267.2 150.6 38.1 (5.3) (36.7) 1,001.8

PPM Energy 4.6 (4.7) (7.2) (1.4) 4.2 3.9 (0.6)

Treasury (i) (151.6) 4.7 14.4 7.2 – 17.7 (107.6)

Total 440.9 267.2 157.8 43.9 (1.1) (15.1) 893.6

Valued based on actively quoted market prices and rates from third party sources (ii) 291.3 160.3 62.6 5.8 4.2 20.0 544.2

Valued based on models and other valuation methods (iii) 149.6 106.9 95.2 38.1 (5.3) (35.1) 349.4

440.9 267.2 157.8 43.9 (1.1) (15.1) 893.6

Derivatives which have a positive fair value are shown in the table above without brackets, while derivatives with a negative fair value are shown as bracketed. (i) Included in this category is the embedded derivative within the 4% US$ convertible bonds. For further details see Note 24(c)(v).

(ii) Included within this category are derivative contracts which are traded in active markets and for which published market price and rate information is available for the whole contract term.

(iii) This category principally includes commodity purchase contracts which extend over liquid and illiquid periods. The liquid periods for power and gas extend to March 2008 and June 2009, respectively. Fair values for these contracts have been calculated utilising forward price curves for illiquid periods which have been developed internally using various models and assumptions that are intended to simulate expected market price levels. Given the proportionately small element of these contracts that falls within the illiquid period, any range of reasonably possible alternative assumptions applied to power and gas prices is unlikely to have a significant impact on contract fair values. For indicative purposes, a 1% movement in commodity prices in the illiquid period would result in an approximately £1.2 million impact on reported fair values.

The weighted average term for the commodity trading portfolio is 1.8 years. The maximum term of any contract is 10.5 years.

The weighted average term of the treasury trading portfolio at year end is 3.8 years. The weighted average term of the hedging derivative instruments is 3.6 years. The maximum term of any contract is 24 years.

26 Effect of hedging and derivative instruments on the results

The group has taken exemption under IFRS 1 from applying the standards IAS 32 and IAS 39 in the comparative period. Accordingly no comparative information is disclosed within footnote (a). Comparative information prepared in accordance with UK GAAP applicable in the comparative period is set out in footnote (b).

(a)

An analysis of the effect of hedging and derivative financial instruments on the income statement is given below:

Notes 2006 £m

Continuing operations

Fair value gains on operating derivatives:

Cash flow hedges

Losses on ineffective hedging recognised in the year (i) (3.3)

Effect of other derivative instruments and fair value contracts

Losses on other derivative market instruments classified as held for trading (ii) (9.5)

Gains on structured contracts 111.8

Losses on embedded derivative components in non-derivative instruments (13.7)

85.3

Continuing operations

Fair value losses on financing derivatives:

Gains on other derivative instruments 9.7

Losses on embedded derivative components in non-derivative instruments (125.1)

(115.4)

Discontinued operations

Fair value gains on operating derivatives:

Gains on other derivative market instruments classified as held for trading 64.6

64.6

Discontinued operations

Fair value losses on financing derivatives:

Losses on other derivative instruments (13.5)

Net investment hedges

Loss following de-designation of net investment hedges (iii) (46.1)

(59.6)

Other items

Fair value hedges

Movements to the fair value of hedging instruments recorded in the year (iv) 1.5

Movements to the fair value of a hedged item recorded in the year (v) (3.2)

Amortisation of movements in fair value of hedged items (vi) 1.2

(0.5)

Cash flow hedges

Gains removed from equity and recognised in the year (vii) 496.4

496.4

Total 470.8

118 ScottishPower Annual Report & Accounts 2005/06

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26 Effect of hedging and derivative instruments on the results continued

(i) These amounts relate to cumulative changes in the fair value of hedging instruments, which have more than offset the cash flow movements on the hedged items. In accordance with IAS 39 the excess gain/loss has been recorded in the income statement classifed as ‘Fair value gains on operating derivatives’. Refer to Note 1(d). (ii) This is the impact on the income statement of amounts valued using models and valuation methods as described in Note 25(f).

(iii) These amounts relate to the loss following de-designation of net investment hedges arising from the group’s US dollar hedging programme relating to PacifiCorp’s net assets on 1 April 2005. Refer to Note 9(c).

(iv) The adjustments relate to the change in fair value of the financial fixed and floating ISDA swaps entered into to hedge the fair value of the coal stock held by the group and a change in fair value of the cross-currency and interest rate swaps entered into to hedge the fair value of foreign currency and sterling debt. (v) The adjustments relate to a change in fair value of the coal stock held by the group as well as a change in the fair value of foreign currency and sterling denominated debt, which have been designated as hedged items in fair value hedging relationships. (vi) The charge for the year relates to amortisation of previously recorded movements in the fair value of hedged items designated in fair value hedging relationships.

(vii) The amount relates to gains and losses on the effective portions of cash flow hedges which have previously been deferred in equity which have been transferred to the income statement in the current year to match timing of occurrence of the hedged cash flows or where hedged forecasted cash flows are no longer expected to occur. The ineffective portions of cash flow hedges are dealt with in (i) above.

(b)

Comparative information

The group has taken exemption under IFRS 1 from applying the standards IAS 32 and IAS 39 to the comparative period. The comparatives relating to hedging and derivative instruments for the year ended 31 March 2005 are presented below under UK GAAP in accordance with the disclosure requirements of FRS 13 – Financial Reporting Standard

13 ‘Derivatives and other financial instruments’.

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:

2005 UK GAAP

Total net Losses gains/(losses)

Gains £m

Note £m £m

Unrecognised gains and (losses) on hedges at 1 April 2004 181.0 (112.6) 68.4

Transfer from gains to losses (i) – – –

Transfer from losses to gains (i) (28.2) 28.2 –

(Gains) and losses arising in previous years that were recognised in 2004/05 (22.2) 10.4 (11.8)

Gains and (losses) arising before 1 April 2004 that were not recognised in 2004/05 130.6 (74.0) 56.6

Gains and (losses) arising in 2004/05 that were not recognised in 2004/05 32.5 39.9 72.4

Unrecognised gains and (losses) on hedges at 31 March 2005 163.1 (34.1) 129.0

(Losses) and gains expected to be recognised in 2005/06 (26.6) 6.2 (20.4)

Gains and (losses) expected to be recognised in 2006/07 or later 136.5 (27.9) 108.6

(i)

Figures in the table above are calculated by reference to the 31 March 2005 fair value of the derivative concerned.

The analysis above excludes any gains and losses in respect of the net investment cross-currency swaps and net investment forward contracts and losses of £17.6 million relating to certain other forward contracts as gains and losses arising on these contracts would have been recognised in the statement of total recognised gains and losses.

27 Obligations under finance leases

2006 £m 2005 £m

Finance leases are repayable as follows:

Current 6.7 14.5

Non-current 58.0 158.8

64.7 173.3

2006 £m 2005 £m

Finance lease liabilities – minimum lease payments:

Within one year 13.2 33.7

Between one and five years 52.1 125.1

More than five years 27.3 129.9

92.6 288.7

Future finance charges on finance leases (27.9) (115.4)

Present value of finance lease liabilities 64.7 173.3

The present value of finance lease liabilities is as follows:

Within one year 6.7 14.5

Between one and five years 33.9 66.0

More than five years 24.1 92.8

64.7 173.3

The group enters into finance leases principally in respect of its US aircraft portfolio. These lease obligations are non-recourse to the group. The finance leases have maturity dates ranging from 2008 to 2015. All leases are on a fixed repayment basis and no arrangements have been entered into for contingent rental payments.

ScottishPower Annual Report & Accounts 2005/06 119

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

28 Trade and other payables

Note 2006 £m 2005 £m

(a)

Current payables:

Trade payables (i) 201.9 134.5

Other taxes and social security 23.5 45.0

Payments received on account 94.5 48.6

Capital payables and accruals 114.2 149.7

Other payables 45.4 268.1

Accrued expenses 890.2 987.0

1,369.7 1,632.9

(b)

Non-current payables:

Other payables 36.6 2.7

36.6 2.7

1,406.3 1,635.6

(i) Trade payables include amounts due on commodity activities. The group has posted amounts of collateral with respect to certain of those liabilities. The value of such collateral posted at 31 March 2006 is £140.8 million.

29 Deferred tax

Deferred tax provided in the Accounts is as follows:

Provided

2006 £m 2005 £m

Accelerated capital allowances 649.5 1,274.5

Other temporary differences 173.8 (113.1)

823.3 1,161.4

Notes Accelerated capital allowances differences £m Other timing Total £m £m

Deferred tax provided at 1 April 2004 1,219.5 (188.9) 1,030.6

Charge to income statement 54.3 77.2 131.5

Acquisitions 17.1 16.7 33.8

Exchange (18.3) 0.8 (17.5)

Other movements 1.9 (18.9) (17.0)

Deferred tax provided at 1 April 2005 1,274.5 (113.1) 1,161.4

Increase arising on implementation of IAS 39 (a) – 109.6 109.6

Deferred tax provided at 1 April 2005 – as restated 1,274.5 (3.5) 1,271.0

Transferred to liabilities classified as held for sale (b) (718.0) 201.8 (516.2)

556.5 198.3 754.8

Charge/(credit) to income statement – continuing operations 45.1 (110.5) (65.4)

Exchange 47.9 (4.7) 43.2

Recorded in the Statement of Recognised Income and Expense (c) – 90.7 90.7

Deferred tax provided at 31 March 2006 649.5 173.8 823.3

(a) On the implementation of IAS 39 on 1 April 2005, certain assets and liabilities of the group were remeasured resulting in an increase in the deferred tax provision of £109.6 million.

(b) On 23 May 2005, the deferred tax provision relating to the PacifiCorp disposal group was reclassified as ‘Liabilities classified as held for sale’ in accordance with IFRS 5. (c) In the Statement of Recognised Income and Expense, the deferred tax charge is offset by a current tax credit of £42.9 million.

120 ScottishPower Annual Report & Accounts 2005/06

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30 Provisions

2004/05 At 1 April 2004 £m Acquisitions New provisions £m Unwinding of discount £m Utilised during year £m Released during year £m Exchange £m At 31 March 2005 £m

Reorganisation and restructuring 3.2 — — — (3.0) — — 0.2

Environmental and health 60.5 — — 0.8 (12.8) (30.8) (0.1) 17.6

Decommissioning costs 84.3 3.5 7.4 5.8 (7.0) — (2.2) 91.8

Onerous contracts 120.5 83.5 — 8.7 (148.1) — — 64.6

Other post-employment benefits 6.5 — 3.3 — (2.6) — (0.2) 7.0

Mine reclamation costs 79.6 — 5.1 3.3 (10.9) — (2.4) 74.7

Other 9.0 — 8.0 — (10.5) — (0.1) 6.4

363.6 87.0 23.8 18.6 (194.9) (30.8) (5.0) 262.3

2005/06 Notes At 1 April 2005 £m Derecognition on implementation of IAS 39 £m Movements in discontinued operations Note (g) £m Transfered to liabilities classified as held for sale Note (g) £m New provisions £m Unwinding of discount £m Utilised during year £m Transferred to retirement benefit obligations £m Exchange £m At 31 March 2006 £m

Reorganisation and restructuring (a) 0.2 — — — 42.0 — (3.5) (18.4) — 20.3

Environmental and health (b) 17.6 — (0.4) (13.5) 1.0 — (1.5) — 0.1 3.3

Decommissioning costs (c) 91.8 — 3.8 (73.4) 4.4 0.9 — — 0.1 27.6

Credit support facility (d) — — — — 33.6 — — — 0.2 33.8

Onerous contracts (e) 64.6 (64.6) — — — — — — — —

Other post-employment benefits 7.0 — 0.4 (7.4) — — — — — —

Mine reclamation costs 74.7 — 2.0 (76.7) — — — — — —

Other (f) 6.4 — (0.1) (2.7) 3.6 — — — 0.1 7.3

262.3 (64.6) 5.7 (173.7) 84.6 0.9 (5.0) (18.4) 0.5 92.3

Analysis of total provisions 2006 £m 2005 £m

Short-term 26.5 80.1

Long-term 65.8 182.2

92.3 262.3

(a) The provision for reorganisation and restructuring was increased during the year by a charge to the income statement of £42.0 million relating to the costs of the corporate restructuring. Of the total charge, £18.4 million relates to payments made to the company’s pension schemes and this amount has been transferred to retirement benefit obligations. The provision was expected to cover the costs of a reduction of employee numbers through redundancies of 356 from 2005/06 onwards, with the balance of the positions to be eliminated through the corporate restructuring being achieved through redeployment and attrition. At 31 March 2006 the group had made redundancy payments under the restructuring to 73 employees.

(b) The environmental and health provisions at 31 March 2005 principally comprised 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 US. These costs were expected to be incurred in the period up to March 2012. Following the completion of a detailed environmental exposure study £30.8 million of the environmental and health provision was released to the income statement in the year ended 31 March 2005.

(c) The provision for decommissioning costs is the discounted future estimated costs of decommissioning the group’s power plants. The decommissioning of these plants is expected to occur over the period between 2012 and 2036.

(d) This provision relates to probable liabilities in relation to a credit support facility provided by PacifiCorp Holdings Inc. (now Scottish Power Holdings Inc.) to certain providers of debt to the Klamath Co-Generation project at the project’s inception in 1999. The project is owned by the City of Klamath Falls, but operated by PPM Energy which has a purchase contract for 47% of the output liabilities. This provision is expected to be utilised in the period to 2017. (e) The provision for onerous contracts comprised the costs of contracted energy purchases. As a consequence of the implementation of IAS 39 on 1 April 2005 the provision for onerous contracts has been derecognised.

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

(g) The movements in provisions relating to the PacifiCorp disposal group in the period from 1 April 2005 to 23 May 2005 (the date when provisions relating to the PacifiCorp disposal group were reclassified as “Liabilities classified as held for sale” in accordance with IFRS 5) were as follows: (i) Environmental and health – utilised during the period £(0.2) million, released during the period £(0.6) million and exchange £0.4 million.

(ii) Decommissioning costs – new provisions £0.9 million, unwinding of discount £0.6 million, utilised during the period £(0.1) million and exchange £2.4 million. (iii) Other post-employment benefits – new provisions £0.6 million, utilised during the period £(0.4) million and exchange £0.2 million.

(iv) Mine reclamation costs – unwinding of discount £0.5 million, utilised during the period £(0.6) million, released during the period £(0.4) million and exchange £2.5 million. (v) Other – new provisions £0.7 million, utilised during the period £(0.9) million and exchange £0.1 million.

31 Deferred income

At 1 April 2004 £m Receivable during year £m Released to income statement £m Disposals/ Other £m Exchange £m At 31 March 2005 £m

Grants and customer contributions 577.8 51.3 (19.2) (37.3) (2.5) 570.1

At 1 April 2005 £m Movements in discontinued operations Note (a) £m Transferred to liabilities classified as held for sale Note (b) £m Receivable during year Note (c) £m Released to income statement £m Disposals/ Other £m Exchange £m At 31 March 2006 £m

Grants and customer contributions 570.1 4.2 (93.5) 25.3 (19.7) (3.6) — 482.8

(a) Movements in grants and customer contributions relating to the PacifiCorp disposal group for the period from 1 April 2005 to 23 May 2005 comprised £2.8 million grants receivable, £(0.3) million released to the income statement and £1.7 million exchange.

(b) On 23 May 2005, those grants and customer contributions relating to the PacifiCorp disposal group were reclassified as ‘Liabilities classified as held for sale’ in accordance with IFRS 5.

(c) Grants and customer contributions receivable during the year of £25.3 million includes grants and contributions of £19.8 million relating to capital expenditure.

ScottishPower Annual Report & Accounts 2005/06 121

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

32 Share capital

2006 £m 2005 £m

Authorised:

3,000,000,000 (2005 3,000,000,000) ordinary shares of 50p each 1,500.0 1,500.0

1,500.0 1,500.0

Allotted, called up and fully paid:

1,871,235,749 (2005 1,865,343,685) ordinary shares of 50p each 935.6 932.7

935.6 932.7

(a)

Employee share schemes

The group has a range of share-based plans for employees. Options have been granted and awards made to eligible employees to subscribe for or receive by transfer ordinary shares or ADSs in Scottish Power plc in accordance with the rules of each plan.

The ScottishPower Sharesave Schemes are savings related and under normal circumstances share options are exercisable on completion of a three or five year save-as-you-earn contract as appropriate.

The PacifiCorp Stock Incentive Plan (“PSIP”) relates to options over ScottishPower ADSs. Following the sale of PacifiCorp on 21 March 2006, participants will have 12 months from the date of sale in which to exercise their 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 number of shares which become exercisable is dependent on the company’s Total Shareholder Return Performance compared to a group of international energy companies.

Options granted under the Executive Share Option Plan 2001 (“ExSOP”) to executive directors and certain senior managers in the UK are subject to the performance criterion that the percentage increase in the company’s annualised earnings per share, excluding goodwill amortisation and exceptional items, be at least 3% (adjusted for any increase in the RPI). Options granted to US participants under the ExSOP are not subject to any outstanding performance criteria.

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 up to a value of £50 per month (Matching Shares) and are also held in trust. At the launch of the ESOP, Free Shares were offered to employees.

(i)

Summary of movements in share options in ScottishPower shares

ScottishPower Sharesave Schemes (number of shares 000s) Weighted average exercise price (pence) Executive Share Option Schemes# (number of shares 000s) Weighted average exercise price (pence) PacifiCorp Stock Incentive Plan## (number of shares 000s) Weighted average exercise price (pence) Total (number of shares 000s)

Outstanding at 1 April 2003 7,441 377.7 9,456 411.5 13,613 500.8 30,510

Granted 2,758 301.0 5,892 352.8 — — 8,650

Exercised (17) 326.8 (102) 320.3 (590) 347.5 (709)

Lapsed (2,794) 392.3 (34) 369.5 (1,327) 469.9 (4,155)

Outstanding at 1 April 2004 7,388 343.6 15,212 376.5 11,696 430.4 34,296

Granted 2,143 312.0 5,911 384.4 — — 8,054

Exercised (298) 382.6 (1,808) 369.5 (3,001) 345.3 (5,107)

Lapsed (1,599) 383.4 (364) 337.8 (161) 441.8 (2,124)

Outstanding at 1 April 2005 7,634 324.9 18,951 382.3 8,534 443.3 35,119

Granted 2,144 374.0 — — — — 2,144

Exercised (1,184) 350.0 (9,701) 387.7 (5,368) 454.2 (16,253)

Lapsed (513) 338.5 (1,204) 455.5 (87) 514.8 (1,804)

Outstanding at 31 March 2006 8,081 333.4 8,046 393.5 3,079 535.0 19,206

Exercisable at 1 April 2003 176 409.0 811 462.3 11,081 516.8 12,068

Exercisable at 1 April 2004 76 382.9 1,439 435.6 10,852 436.6 12,367

Exercisable at 1 April 2005 3 344.1 4,100 428.8 8,534 443.3 12,637

Exercisable at 31 March 2006 73 329.2 4,996 399.6 3,079 535.0 8,148

# The Executive Share Option figures are a combination of the options outstanding under the Executive Share Option Scheme and the ExSOP.

## PacifiCorp Stock Incentive Plan are options over ScottishPower ADSs; for the purpose of the table above, ADSs have been converted to ScottishPower shares as follows: one ScottishPower ADS equals four ScottishPower ordinary shares. Participants have 12 months from the date of the sale of PacifiCorp to exercise their options. Eligibility for participation in the ExSOP was extended during the year ended 31 March 2003 to certain senior managers in the US.

122 ScottishPower Annual Report & Accounts 2005/06

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32 Share capital continued

(ii) Analysis of share options outstanding at 31 March 2006

Date of grant Number of participants Number of options outstanding (000s) Option price (pence) Normal exercisable date

ScottishPower Sharesave Schemes 9 June 2000 2 1 453.0 6 months to March 2006

June 2001 597 821 386.0 6 months to March 2007

June 2002 595 1,151 323.0 6 months to March 2006 or 2008

June 2003 1,542 2,274 301.0 6 months to March 2007 or 2009

24 June 2004 1,501 1,826 312.0 6 months to March 2008 or 2010

22 June 2005 1,941 2,008 374.0 6 months to March 2009 or 2011

Executive Share Option Plan 2001

UK# 21 August 2001 70 666 483.0 21 August 2004 to 21 August 2011

UK# 2 May 2002 42 915 406.0 2 May 2005 to 2 May 2012

US standard* 2 May 2002 20 245 339.1 2 May 2003 to 2 May 2012**

US conditional* # 2 May 2002 11 153 339.1 2 May 2005 to 2 May 2012

UK## 10 May 2003 102 2,006 376.3 10 May 2006 to 10 May 2013

US* 10 May 2003 72 599 351.4 10 May 2004 to 10 May 2013**

UK## 27 May 2004 111 2,414 389.3 27 May 2007 to 27 May 2014

US* 27 May 2004 86 1,048 413.6 27 May 2005 to 27 May 2014**

Pacificorp Stock Incentive Plan 3 June 1997 10 115 490.5 29 November 1999 to 3 June 2007***

12 August 1997 4 33 527.6 29 November 1999 to 12 August 2007***

10 February 1998 63 1,116 595.9 29 November 1999 to 10 February 2008***

13 May 1998 3,545 819 575.9 29 November 1999 to 13 May 2008***

9 February 1999 11 183 471.7 9 February 2000 to 9 February 2009***

11 May 1999 1,454 335 426.8 11 May 2000 to 11 May 2009***

16 February 2000 5 52 388.0 16 February 2001 to 16 February 2010***

24 March 2000 1 381 457.2 24 March 2001 to 24 March 2010***

24 April 2001 5 45 370.1 24 April 2002 to 24 April 2011***

* Options granted under the Executive Share Option Plan 2001 to US based participants and options granted under the PacifiCorp Stock Incentive Plan are over ScottishPower ADSs. For the purpose of the table above, such options have been converted to ScottishPower ordinary shares as follows: one ScottishPower ADS equals four ScottishPower ordinary shares. The US$ ADS option exercise 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 2006 to be quoted in pence in the table above. Eligibility for participation in the Executive Share Option Plan 2001 was extended during the year ended 31 March 2003 to executive directors and certain senior managers in the US.

** Options become exercisable in the following proportions: one third on the first anniversary of grant, a further one third on the second anniversary of grant, and the final one third on the third anniversary of grant.

*** Following the sale of PacifiCorp, participants will have 12 months in which to exercise their options.

# Performance condition applied which has now been met.

## Performance condition applied which as yet is untested.

Where reference is made to PacifiCorp Stock Incentive Plan, this is to identify the plan under which the options over ScottishPower 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.

(iii) Range of exercise prices and remaining contractual life of share options at 31 March 2006

Range of exercise prices Number outstanding Options outstanding Weighted average remaining contractual life (months) Weighted average exercise price (pence) Options exercisable Number exercisable Weighted average exercise price (pence)

Between 300.5p and 350.0p 5,649 27 311.7 453 335.3

Between 350.5p and 400.0p 7,945 65 378.8 2,083 373.6

Between 400.5p and 450.0p 2,298 36 412.5 2,298 412.5

Between 450.5p and 500.0p 1,346 38 474.8 1,346 474.8

Between 500.5p and 550.0p 33 12 527.6 33 527.6

Between 550.5p and 600.0p 1,935 12 587.4 1,935 587.4

Total 19,206 43 391.1 8,148 450.6

ScottishPower Annual Report & Accounts 2005/06 123

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

32 Share capital continued

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

2004/05 Notes Dividends waived Shares held at 1 April 2004 (000s) Shares acquired during year (000s) Shares transferred during year (000s) Shares held at 31 March 2005 (000s) Nominal value at 31 March 2005 £m Market value at 31 March 2005 £m

Long Term Incentive Plan (a) no 3,979 976 (896) 4,059 2.0 16.6

ScottishPower Sharesave Schemes (b) yes 6,243 — (298) 5,945 3.0 24.3

Executive Share Option Plan 2001 (c) yes 15,546 5,530 (1,949) 19,127 9.6 78.2

PacifiCorp Stock Incentive Plan (d) no 59 — (34) 25 — 0.1

Employee Share Ownership Plan (e) no 3,815 1,181 (1,060) 3,936 2.0 16.1

29,642 7,687 (4,237) 33,092 16.6 135.3

2005/06 Notes Dividends waived Shares held at 1 April 2005 (000s) Shares acquired during year (000s) Shares transferred during year (000s) Shares held at 31 March 2006 (000s) Nominal value at 31 March 2006 £m Market value at 31 March 2006 £m

Long Term Incentive Plan (a) no 4,059 — (588) 3,471 1.7 20.2

ScottishPower Sharesave Schemes (b) yes 5,945 — (1,184) 4,761 2.4 27.7

Executive Share Option Plan 2001 (c) yes 19,127 — (9,771) 9,356 4.7 54.5

PacifiCorp Stock Incentive Plan (d) no 25 — (25) — — —

Employee Share Ownership Plan (e) no 3,936 959 (1,331) 3,564 1.8 20.7

33,092 959 (12,899) 21,152 10.6 123.1

(a) Shares of the company are held under trust as part of the Long Term Incentive Plan for executive directors and other senior managers (see Remuneration Report of the Directors on pages 57 to 68 for details of the Plan). (b) Shares of the company are held in two Qualifying Employee Share Ownership Trusts as part of the Scottish Power plc Sharesave Scheme and the Scottish Power UK plc Sharesave Scheme. Holders of options granted under the Scottish Power plc scheme will be transferred shares by the associated Trust upon the exercise of the options.

As there are no longer any options outstanding under the Scottish Power UK plc scheme, it is intended to transfer shares held in the Scottish Power UK plc trust to the Scottish Power plc trust at a future time. Details of options granted under these schemes are disclosed above.

(c) Shares of the company are held under trust as part of the Executive Share Option Plan 2001 for executive directors and other senior managers (see Remuneration Report of the Directors on pages 57 to 68 for details of the Plan).

(d) Options granted under the PacifiCorp Stock Incentive Plan were over ScottishPower ADSs; for the purposes of the table above, ADS options have been converted to ScottishPower ordinary share options as follows: one ScottishPower ADS option equals four ScottishPower ordinary share options. (e) 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.

(f) The company’s practice has been to purchase shares in the market through an employee benefit trust to satisfy options and awards granted under the Executive Share Option Plan 2001 and the Long Term Incentive Plan. New shares have been issued in relation to the Qualifying Employee Share Trusts associated with the Sharesave Schemes, the Executive Share Option Scheme, the PacifiCorp Stock Incentive Plan and the Employee Share Ownership Plan in the last ten years. In the ten year period to 31 March 2006, new shares issued to satisfy discretionary options and awards represented 0.58% of the issued share capital. New shares issued to satisfy options and awards under all share plans represented 3.75% of the issued share capital, leaving available dilution headroom of 6.25%.

(v)

Share option pricing

For the purposes of valuing options to arrive at the stock-based compensation charge, the Binomial model or the Monte Carlo option pricing models have been used, as appropriate. The assumptions used in the models were as follows:

Binomial Model Monte Carlo model

2006 2005 2006 2005

Dividend yield 6.3% 6.6% 4.9% 5.3%

Risk-free interest rate 4.1% 5.0% n/a n/a

Volatility 20.8% 24.3% 15.3% 14.4%

Expected life of the options (years) 1-5 1-5 3 3

Binomial model

The expected volatility is based on historical volatility over the last three years and the risk-free interest rate is the yield on UK government bonds of a term consistent with the assumed option life.

Monte Carlo model

The expected volatility is based on historical volatility over the last two years. The weighted average fair value of share options granted during the period were:

2006 pence 2005 pence

Long Term Incentive Plan 197.0 166.0

ScottishPower Sharesave Schemes 66.0 71.0

Executive Share Option Plan 2001 — 59.0

Employee Share Ownership Plan 476.0 368.0

The charge for share-based payments in respect of share options is £7.9 million (2005 £6.8 million) which comprised entirely of equity-settled transactions.

124 ScottishPower Annual Report & Accounts 2005/06

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32 Share capital continued

(vi) Purchases of equity securities made by the issuer during the year

No share purchases in the market were made during the year pursuant to the LTIP and the ExSOP. The company’s policy is to purchase in the market only the number of shares required to satisfy options and awards granted under the LTIP and the ExSOP.

The company obtained authority from shareholders at its 2005 AGM to make market purchases of up to 185,999,745 ordinary shares during the period of approximately 12 months after the AGM. On 10 February 2006, 1,750,000 ordinary shares were purchased for cancellation at an average price of 596.5 pence per share.

(b)

Subsequent events

On 4 May 2006 shareholder approval was obtained at an Extraordinary General Meeting of the company for a proposed return of cash to shareholders of £2.25 billion via a B share structure including a capital restructuring, reorganisation and the issue of new ordinary shares and B shares. Further details are given in Note 41.

33 Analysis of movements in equity attributable to equity holders of Scottish Power plc

Note Number of shares 000s Share capital £m Share premium £m Hedge reserve £m Translation reserve £m Other reserves £m Retained earnings/ (loss) £m Total £m

At 1 April 2004 1,859,539 929.8 2,275.7 — 484.6 424.7 399.1 4,513.9

Exchange movement on translation of overseas results and net assets — — — — (100.2) — — (100.2)

Gains on net investment hedges — — — — 146.6 — — 146.6

Actuarial losses on retirement benefits — — — — — — (63.3) (63.3)

Tax on items taken directly to equity — — — — (46.4) — 18.9 (27.5)

Loss for the year attributable to equity holders of Scottish Power plc — — — — — — (193.4) (193.4)

Dividends — — — — — — (386.1) (386.1)

Revaluation reserve arising on the purchase of the remaining

50% of the Brighton Power Station — — — — — 5.8 — 5.8

Share capital issued

– ESOP 2,776 1.4 9.8 — — — — 11.2

– PacifiCorp Stock Incentive Plan 3,029 1.5 9.2 — — — — 10.7

Consideration paid in respect of purchase of own shares held under trust — — — — — — (30.7) (30.7)

Credit in respect of employee share awards — — — — — — 6.8 6.8

Consideration received in respect of sale of own shares held under trust — — — — — — 7.6 7.6

At 1 April 2005 1,865,344 932.7 2,294.7 — 484.6 430.5 (241.1) 3,901.4

Cumulative adjustment for the implementation of IAS 39 (net of tax) 43 — — — 416.6 (2.1) — (133.1) 281.4

At 1 April 2005 – as restated 1,865,344 932.7 2,294.7 416.6 482.5 430.5 (374.2) 4,182.8

Gains on effective cash flow hedges recognised — — — 747.9 — — — 747.9

Exchange movement on translation of overseas results and net assets — — — — 244.1 — — 244.1

Cumulative translation gain transferred to income statement on

disposal of discontinued operations (net of tax) — — — — (484.6) — — (484.6)

Losses on net investment hedges — — — — (276.5) — — (276.5)

Gains on revaluation of available-for-sale securities — — — — — — 0.4 0.4

Actuarial gains on retirement benefits — — — — — — 39.1 39.1

Tax on items taken directly to equity — — — (224.9) 42.7 — (11.0) (193.2)

Profit for the year attributable to equity holders of Scottish Power plc — — — — — — 1,543.3 1,543.3

(Gains)/losses removed from equity and recognised in the year — — — (493.1) — — 8.6 (484.5)

Tax on items transferred from equity — — — 148.7 — — (3.3) 145.4

Dividends — — — — — — (428.1) (428.1)

Share capital issued

– ESOP 2,343 1.1 11.0 — — — — 12.1

– PacifiCorp Stock Incentive Plan 5,299 2.7 20.3 — — — — 23.0

Share buy-back (1,750) (0.9) — — — 0.9 (10.4) (10.4)

Consideration paid in respect of purchase of own shares held under trust — — — — — — (3.3) (3.3)

Credit in respect of employee share awards — — — — — — 7.9 7.9

Consideration received in respect of sale of own shares held under trust — — — — — — 35.5 35.5

At 31 March 2006 1,871,236 935.6 2,326.0 595.2 8.2 431.4 804.5 5,100.9

ScottishPower Annual Report & Accounts 2005/06 125

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

33 Analysis of movements in equity attributable to equity holders of Scottish Power plc continued

(a) Other reserves comprise a revaluation reserve of £5.8 million (2005 £5.8 million), a capital redemption reserve of £19.2 million (2005 £18.3 million) and a merger reserve of £406.4 million (2005 £406.4 million).

(b)

Expected realisation of the hedge reserve

The following represents the profile of gains and losses included within the hedge reserve at the year end, which are expected to be realised in the income statement in the course of the next 5 years and thereafter.

Hedge reserve 2007 £m 2008 £m 2009 £m 2010 £m 2011 £m Thereafter £m Total £m

Gains and (losses) on effective cash flow hedges 507.5 190.8 110.5 36.2 6.3 3.3 854.6

Deferred tax (259.4)

Net hedge reserve 595.2

(c)

Cumulative goodwill written off to retained earnings as at 31 March 2006 was £572.3 million (2005 £572.3 million).

34 Minority interests

Notes Equity 2006 £m Non-equity 2006 £m Total 2006 £m Equity 2005 £m Non-equity 2005 £m Total 2005 £m

At 1 April 3.2 52.5 55.7 3.4 57.5 60.9

Reclassification on implementation of IAS 32 (a) — (52.5) (52.5) — — —

At 1 April – as restated 3.2 — 3.2 3.4 57.5 60.9

Redemption of preferred stock of PacifiCorp (b) — — — — (4.1) (4.1)

Group income statement 0.4 — 0.4 1.3 3.4 4.7

Dividends paid to minority interests (2.5) — (2.5) (1.5) (2.8) (4.3)

Acquisition of the remaining 50% of a subsidiary (1.0) — (1.0) — — —

Exchange — — — — (1.5) (1.5)

At 31 March 0.1 — 0.1 3.2 52.5 55.7

(a) On the implementation of IAS 32 on 1 April 2005, minority interests previously classified as non-equity were reclassified as liabilities.

(b) Non-equity minority interests at 31 March 2005 included 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 2005, £2.0 million was due to be redeemed within 1 year, £2.0 million was due to be redeemed within the following year with the remaining £23.8 million redeemable after 2 years. The fair value of preferred stock subject to mandatory redemption at 31 March 2005 was £29.6 million. The fair value of other preferred stock was not materially different from its book value. The weighted average rate of return on preferred stock subject to mandatory redemption was 7.5% and on other preferred stock was 5.1%.

126 ScottishPower Annual Report & Accounts 2005/06

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35 Retirement benefit obligations

(a)

Group pension arrangements

Following a review of the group’s UK pension arrangements, the ScottishPower Final Salary LifePlan and the ScottishPower Executive Top-Up Plan were merged with the ScottishPower Pension Scheme as at 31 March 2006. This will lead to economies of scale in relation to the ongoing running costs in the delivery of the pension benefits due to the group’s current and past staff. From 1 April 2006 new entrants will have access to a defined contribution Stakeholder Pension Plan. The merged ScottishPower Pension Scheme and the Manweb Pension Scheme are closed to new entrants.

In the UK pension arrangements the age profile of the two closed defined benefit schemes is expected to rise over time, due to the lack of new entrants. This will in turn result in increasing service costs for these two schemes due to the method of actuarial valuation used (the projected unit method). The group believes that the projected unit method is appropriate when adopted across all schemes (closed and open), and in aggregate provides a reasonable basis for assessing the group’s pension costs.

As a result of the proposed return of cash to shareholders and capital reorganisation on the sale of PacifiCorp, ScottishPower reached agreement with the trustees of the UK Pension schemes to make special contributions to each scheme in order to fund the deficit (as at 31 December 2005) in respect of each scheme over a period of up to 5 years.

ScottishPower made an aggregate lump sum payment of £28.2 million during March 2006 into the relevant schemes. On completion of the return of cash to shareholders, an aggregate lump sum contribution of £100.0 million will be made to the relevant schemes and four further aggregate annual payments of £13.2 million will be made to the relevant schemes commencing on 31 March 2007, subject to a deficit continuing in those schemes at each due payment date. ScottishPower has received a clearance statement from the Pensions Regulator, that it would not be reasonable to impose liability for a contribution notice on the applicants to the clearance application in respect of the proposed return of cash.

Each of the pension schemes are invested in an appropriately diversified range of equities, bonds, property and private markets. The broad proportions of each asset class in which the schemes aim to be invested are as follows, however it is important to note that this may vary from time to time as markets change and as cash may be held for strategic reasons.

Equities % Bonds % Property % Private markets % Total %

ScottishPower 66 26 8 — 100

Manweb 60 40 — — 100

Final Salary LifePlan 100 — — — 100

US pensions 58 35 — 7 100

US other post-retirement benefits 64 35 — 1 100

In broad terms, the investment strategies adopted by the schemes aim to ensure that sufficient assets are available to meet scheme liabilities as they fall due. The ScottishPower and Manweb schemes’ investment strategies reflect the large and growing proportion of their liabilities which relate to pensions in payment and therefore include a growing bond element. A significant equity element is still retained, however, to provide potential for long-term outperformance relative to bonds and therefore to reduce the group’s contribution requirements. This strategy will be reviewed on an ongoing basis by the trustees and they will continue to seek the company’s views and comments on asset allocation.

US arrangements are managed and invested in accordance with all applicable requirements, including the Employee Retirement Income Security Act (“ERISA”) and the Internal Revenue Service (“IRS”) revenue code. The ERISA is the US legislation which regulates pension institutions in a number of areas. The US arrangements employs an investment approach whereby a mix of equities and fixed income investments are used to maximise the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed income investments. Equity investments are diversified across US and non-US stocks, as well as growth, value, small and large capitalisation. Fixed income investments are diversified across US and non-US bonds. Other assets such as private equity are used judiciously with a view to enhancing long-term returns while improving portfolio diversification. The US arrangements primarily minimises the risk of large losses through diversification but also monitors and manages other aspects of risk through quarterly investment portfolio reviews, annual liability measurements and periodic asset / liability studies.

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 formal 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 110,168 ScottishPower shares (£641,177, based on market value as at 31 March 2006), 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.

Following the formal actuarial valuation of the Scheme as at 31 March 2003, employer contributions of 15% of pensionable salaries were reinstated from that date. At the point of the merger of the Final Salary LifePlan and the Executive Top-Up Plan into the ScottishPower Pension Scheme the company paid a lump sum payment of £14.8 million to fund the deficits in these schemes. This amount was paid in March 2006 and, on completion of the return of cash to shareholders, a further £18.0 million lump sum payment will be paid to the scheme. Four annual payments of £2.0 million will be made to the scheme commencing on 31 March 2007, subject to a deficit continuing in those schemes at each due payment date.

ScottishPower Annual Report & Accounts 2005/06 127

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

35 Retirement benefit obligations continued

Manweb

Prior to 1 January 1999, most of the Manweb employees were entitled to join the Manweb Group of the Electricity Supply Pension Scheme, which provides pension and other related benefits based on final pensionable salary to employees throughout the Electricity Supply Industry in England & Wales. The ongoing contributions to the Scheme are based on the results of the formal actuarial valuation of the Scheme and the advice of the Scheme Actuary.

The assets are held in a separate trustee administered fund. The Scheme assets no longer include any ScottishPower shares. For funding and expensing purposes the Scheme assets are taken at market value plus a smoothing adjustment appropriate at the valuation date.

The pension charge for the year is based on advice from an independent qualified actuary.

The actual contributions payable by participating employers during the year ranged between 8.1% and 14.1% for different sections of membership (but tending towards the higher rates), or other rates for particular groups or as required by a business transfer agreement. The rates of contributions payable have been reviewed following the results of the formal actuarial valuation of the Scheme as at 31 March 2004. The contributions payable have been increased, principally by a lump sum payment paid in March 2005 of £26.8 million. As described above, as a result of the return of cash to shareholders following the sale of PacifiCorp, the company agreed an enhanced funding plan with the trustees, a £13.4 million lump sum payment was paid in March 2006 and, on completion of the return of cash to shareholders, a further £82.0 million lump sum payment will be paid to the scheme. Four annual payments of £11.2 million will be made to the scheme commencing on 31 March 2007, subject to a deficit continuing in those schemes at each due payment date.

Final Salary LifePlan

Up until 31 March 2005 the assets of the LifePlan were held in a separate trustee administered fund. The pension charge for the year is based on the advice of the LifePlan’s independent qualified actuary, representing the assessed balance of cost of the accruing benefits after allowing for members’ contributions of 5% of pensionable salaries. The same actuarial assumptions have been adopted for both funding and expensing purposes.

The Final Salary LifePlan closed to new entrants with effect from 31 March 2006. A seperate Stakeholder Pension Plan was established for new entrants from 1 April 2006. Future service benefits within the Final Salary Life Plan were also changed from that date. Most significantly, the Normal Retirement Age was increased from 63 to 65 and pension increases in payment were reduced from the increase in the Retail Prices Index subject to a maximum of 5% p.a. to a maximum of 2.5% p.a. From 1 April 2006 the LifePlan benefits will be provided from the LifePlan section of the merged ScottishPower Pension Scheme.

The actual contributions payable by participating employers during the year were 15% of pensionable salaries, except where required by a business transfer agreement.

US arrangements

The US businesses operate pension plans covering substantially all their 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 which can be deducted for federal income tax purposes. The US businesses pension figures in these Accounts include the unfunded SERP. The SERP accounts for less than 5% of the US businesses’ liabilities. The US businesses meet the entire cost of accruing benefits under the US businesses’ 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.

In March 2006 the regulated business, PacifiCorp was sold by ScottishPower, with ScottishPower retaining the US non-regulated businesses. The disposal of PacifiCorp is reflected in the closing deficit position for US pension arrangements.

The pension charge for the year is based on the advice of the Plan’s independent qualified actuary.

The actual contributions payable by participating employers during the year were 15.9% of pensionable earnings. The employers’ planned contribution for 2006/07 are 6.0% of pensionable earnings.

The US businesses also provided other post-retirement benefits to certain employees. The group has provided £2.9 million as at 31 March 2006 (2005 £133.2 million) for these benefits. The related charge for the year was £8.5 million (2005 £21.3 million). The split of the charge between continuing and discontinued operations was £0.3 million and £8.2 million respectively. Further details of these benefits are disclosed below.

Additional pension arrangements

The group also operates pension arrangements for senior executives, namely the ScottishPower Executive Top-Up Plan (for benefits which are held within UK Inland Revenue limits) and the Unfunded Unapproved Retirement Benefit Scheme (“UURBS”) for benefits beyond these limits. The UURBS has no invested assets and the group has provided £22.2 million as at 31 March 2006 (2005 £17.4 million) for the benefit promises which will ultimately be paid by the group.

Further details of the group’s pensions arrangements, as required under US GAAP, are disclosed in Note 44.

(b)

The amounts recognised in the balance sheet in respect of retirement benefit obligations are detailed below:

31 March 2006 £m 31 March 2005 £m

UK pension arrangements (145.6) (210.4)

US pension arrangements (7.0) (291.9)

US other post-retirement benefits (2.9) (133.2)

(155.5) (635.5)

128 ScottishPower Annual Report & Accounts 2005/06

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35 Retirement benefit obligations continued

(c)

Pensions

The group operates defined benefit and defined contribution pension schemes as described earlier in this Note. Formal actuarial valuations were carried out as described earlier and updated to 31 March 2006 by a qualified independent actuary. The pension figures shown below for the year ended 31 March 2006 and for the year ended 31 March 2005 comply with the current pension accounting standard, IAS 19. Figures are shown separately for the UK and US arrangements. The major assumptions applied by the actuary are given in footnote (e).

UK pension arrangements Value at 31 March 2006 UK pension arrangements Value at 31 March 2005 US pension arrangements Value at 31 March 2006 US pension arrangements Value at 31 March 2005

(i)

Analysis of net liability relating to pensions £m £m £m £m

Present value of funded obligations (2,808.7) (2,443.8) (23.7) (710.3)

Fair value of scheme assets 2,685.3 2,250.8 18.7 418.4

(123.4) (193.0) (5.0) (291.9)

Present value of unfunded obligations (22.2) (17.4) (2.0) —

Net liability (145.6) (210.4) (7.0) (291.9)

Amounts in the balance sheet:

Liabilities (145.6) (210.4) (7.0) (291.9)

Assets — — — —

Net liability (145.6) (210.4) (7.0) (291.9)

(ii) The amounts recognised are as follows:

UK pension arrangements Year to 31 March 2006 £m UK pension arrangements Year to 31 March 2005 £m US pension arrangements Year to 31 March 2006 £m US pension arrangements Year to 31 March 2005 £m

Current service cost 43.4 35.5 17.7 14.9

Interest on obligation 129.9 127.0 42.5 39.6

Expected return on scheme assets (143.7) (135.2) (40.1) (35.4)

Past service cost 18.5 — — 1.3

Total income statement charge* 48.1 27.3 20.1 20.4

Actual return on scheme assets 469.0 209.6 56.0 35.6

Net actuarial (gains)/losses recognised in the Statement of Recognised Income and Expense (49.1) 64.6 (3.9) 24.4

The amounts above are stated before capitalisation of employee costs relating to self-constructed assets.

(iii) The split of the amounts recognised in the income statement, in relation to the US pension arrangements for the years ending 31 March 2006 and 2005 between continuing

and discontinued operations is as follows:

Continuing operations Discontinued operations

US pension arrangements Year to 31 March 2006 £m US pension arrangements Year to 31 March 2005 £m US pension arrangements Year to 31 March 2006 £m US pension arrangements Year to 31 March 2005 £m

Current service cost 0.9 0.5 16.8 14.4

Interest on obligation 1.2 1.0 41.3 38.6

Expected return on scheme assets (1.1) (1.0) (39.0) (34.4)

Past service cost — 0.1 — 1.2

Total income statement charge* 1.0 0.6 19.1 19.8

Actual return on scheme assets 1.5 0.1 54.5 35.5

Net actuarial losses/(gains) recognised in the Statement of Recognised Income and Expense — 0.6 (3.9) 23.8

The amounts above are stated before capitalisation of employee costs relating to self-constructed assets.

(iv) Changes in the present value of the defined benefit obligation are as follows:

UK pension arrangements Year to 31 March 2006 £m UK pension arrangements Year to 31 March 2005 £m US pension arrangements Year to 31 March 2006 £m US pension arrangements Year to 31 March 2005 £m

Defined benefit obligation at 1 April 2,461.2 2,257.3 710.3 692.1

Current service cost 43.4 35.5 17.7 14.9

Interest on obligation 129.9 127.0 42.5 39.6

Scheme members’ contributions 10.4 8.9 — —

Past service costs 18.5 — — 1.3

Actuarial losses 276.2 139.0 12.0 24.6

Liabilities extinguished on settlements — — (0.9) —

Disposal of PacifiCorp — — (765.3) —

Benefits paid (108.7) (106.5) (49.6) (42.5)

Exchange differences on foreign plans — — 59.0 (19.7)

Defined benefit obligation at 31 March 2,830.9 2,461.2 25.7 710.3

Analysis of defined benefit obligation

Plans that are wholly or partly funded 2,808.7 2,443.8 23.7 710.3

Plans that are wholly unfunded 22.2 17.4 2.0 —

Total 2,830.9 2,461.2 25.7 710.3

ScottishPower Annual Report & Accounts 2005/06 129

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Accounts 2005/06

Notes to the Group Accounts continued

for the year ended 31 March 2006

35 Retirement benefit obligations continued

(v)

Changes in the fair value of scheme assets are as follows:

UK pension arrangements Year to 31 March 2006 £m UK pension arrangements Year to 31 March 2005 £m US pension arrangements Year to 31 March 2006 £m US pension arrangements Year to 31 March 2005 £m

Fair value of scheme assets at 1 April 2,250.8 2,085.3 418.4 402.0

Expected return on scheme assets 143.7 135.2 40.1 35.4

Actuarial gains 325.3 74.4 15.9 0.2

Assets distributed on settlements — — (1.1) —

Employer contributions 63.8 53.5 38.5 35.9

Scheme members’ contributions 10.4 8.9 — —

Disposal of PacifiCorp — — (476.3) —

Benefits paid (108.7) (106.5) (49.6) (42.5)

Exchange differences on foreign plans — — 32.8 (12.6)

Fair value of scheme assets at 31 March 2,685.3 2,250.8 18.7 418.4

(d)