Edgar Filing: SCOTTISH POWER PLC

2004/05 NINE MONTH RESULTS including 3rd Quarter to 31 December 2004

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

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

THE SECURITIES EXCHANGE ACT OF 1934

For the month of February 2005

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. Announcement of Scottish Power plc, regarding third quarter and nine month financial results to December 31, 2004.

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: February 22, 2005	By:	/s/ Donald McPherson
		Donald McPherson
		Assistant Company Secretary


SCOTTISH POWER plc

2004/05 NINE MONTH RESULTS including 3rd Quarter to 31 December 2004

Cautionary Statement Regarding Non-GAAP Financial Information

ScottishPower management assesses the underlying performance of its businesses by adjusting UK Generally Accepted Accounting Principles (“GAAP”) statutory results to exclude items it considers to be non-operational in nature. In the periods presented, goodwill amortisation has been excluded because it is a recurring, non-operational item and ScottishPower management assesses the performance of its business excluding this item, 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 excluding goodwill amortisation. In the particular circumstances of the current financial year to date and the previous two financial years, the charge recognised for goodwill amortisation has remained broadly similar and, therefore, would not have significantly impacted period-on-period comparison of financial performance.

Goodwill amortisation is a financially material item within ScottishPower’s Accounts and is not common to all UK registered companies. UK analysts and the business community in general regularly exclude goodwill amortisation when assessing and forecasting the results of UK companies. Presenting ScottishPower’s results both including and excluding this non-operational item, 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 goodwill amortisation is additional disclosure to that required under UK GAAP. Furthermore, ScottishPower recognises that such non-GAAP performance measures should not be viewed as replacements for, or alternatives to, comparable GAAP 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.

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 UK GAAP, provide useful information to both management and investors and enhance an understanding of ScottishPower’s reported results. As equal prominence is given to performance measures including and excluding goodwill amortisation within the following discussion, ScottishPower management does not consider the inclusion of non-GAAP measures specifically relating to the exclusion of goodwill, disadvantages or materially constrains a reader’s ability to assess ScottishPower’s performance.

ScottishPower considers that the current UK GAAP accounting treatment of goodwill amortisation does not satisfactorily reflect the economic reality of the value utilisation or contribution made by its investments. Goodwill amortisation is therefore excluded 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. ScottishPower has historically reported these non-GAAP performance measures to the investment community and believes that their inclusion provides consistency in its financial reporting. Looking forward, the introduction from 1 April 2005, of International Financial Reporting Standard 3 “Business Combinations” will prohibit the amortisation of goodwill and instead will require an impairment test to be performed on at least an annual basis. This will remove the goodwill amortisation charge currently reported as part of the group’s profit and loss account.

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 UK GAAP figures have also been prominently discussed and reconciled to the non-GAAP figures. The third quarter and nine months statutory results are presented in the “Group Profit and Loss Account” and in Note 2 “Segmental information”. Unless otherwise stated “nine months” relates to the nine months to 31 December 2004, and “quarter” relates to the three months to 31 December 2004.

The following discussion, which contains information updated only through 10 February 2005, should be read in conjunction with the consolidated financial statements and the related

notes provided elsewhere in this Form 6-K and with the information, including the consolidated financial statements and related notes, provided in ScottishPower’s Annual Report and Accounts on Form 20-F for the year ended 31 March 2004.

1. Introduction

ScottishPower is an international energy business, listed on both the London and New York Stock Exchanges, with 2003/04 annual turnover of £5.8 billion and operating profit of £1 billion. The group comprises four businesses operating in both a regulated and competitive environment in the UK and US, which, at December 2004, served over 6.6 million (March 2004: 5.8 million) electricity and gas customers. The group considers its core strengths to lie in a number of key areas, including strong asset management skills; its integrated approach to energy and risk management; a dedicated customer service focus; and careful management of regulatory partnerships.

The regulated businesses comprise PacifiCorp in the US and Infrastructure Division in the UK. PacifiCorp is a regional vertically integrated utility operating in six US states, servicing almost 1.6 million customers. At operating profit level, it is the largest of our divisions. Infrastructure Division, our UK wires business, owns and manages a substantial UK electricity transmission and distribution network and, at operating profit level, it is our second largest division.

The competitive businesses are the UK Division and PPM in the US. The UK Division is an integrated commercial energy generation and supply business, which balances and hedges energy demand from a diverse generation portfolio through to a national customer base of over 5 million customers. The UK Division operates over 6,200 MW of generating capacity, comprising coal, gas, hydroelectric and wind power generation assets, giving the Division a particularly flexible portfolio. PPM commenced substantive operations in 2001 and supplies energy from clean and efficient natural gas and wind generation facilities and gas storage services to wholesale customers in the mid-western and western US and Canada. It has over 1,600 MW of thermal and renewable generation and 67 BCF of gas storage under its ownership or control.

2. Financial Overview


Table 1 – Financial highlights (unaudited)

Quarter 3			Nine Months
2004/05	2003/04	£m, except per share amounts	2004/05	2003/04

1,856.9	1,524.0	Turnover	4,911.0	4,049.2

297.7	279.0	Operating profit	769.5	731.1
29.0	31.7	Goodwill amortisation	88.8	98.5
326.7	310.7	Operating profit excluding goodwill*	858.3	829.6

252.3	226.2	Profit before tax	634.2	552.8
29.0	31.7	Goodwill amortisation	88.8	98.5
281.3	257.9	Profit before tax excluding goodwill*	723.0	651.3

9.53	8.48	Earnings per share (pence)	23.73	20.39
1.58	1.73	Earnings per share impact of goodwill (pence)	4.85	5.38
11.11	10.21	Earnings per share excluding goodwill (pence)*	28.58	25.77

4.95	4.75	Dividends per share (pence)	14.85	14.25

*	Non-GAAP performance measure (see “Cautionary Statement Regarding Non-GAAP Financial Information” above).

Group Profit and Loss

Group turnover increased by £333 million to £1,857 million for the quarter and by £862 million to £4,911 million for the nine months. The weaker US dollar reduced sterling revenues by £51 million in the quarter and by £178 million for the nine months, net of hedging benefits from the forward sale of dollars. The effect of the weaker dollar on PPM and PacifiCorp sterling revenues is mitigated at an earnings level by the favourable effect of the weaker dollar on costs and by our hedging strategy. PacifiCorp’s dollar turnover increased by 13% in the quarter and 8% for the nine months, primarily due to higher wholesale and retail revenues. Infrastructure Division’s turnover increased by 8% in the quarter and 11% for the nine months due to higher regulated and new connections business revenues, both driven by higher volumes. The UK Division’s turnover grew by 31% and 40% for the quarter and nine months respectively, as a result of higher retail sales, increased energy balancing activities and the acquisition of generation plant. PPM’s dollar turnover was higher by 90% in the quarter and 87% for the nine months due to increased energy management revenues from its contract storage and energy positions and increased revenues from new wind resources and gas storage facilities at Katy and Alberta.

Cost of sales increased by £272 million to £1,254 million for the quarter and by £746 million to £3,255 million for the nine months, reflecting growth in balancing our UK electricity and gas positions; increased power production and purchase costs in both UK Division and PacifiCorp; the acquisition of Damhead Creek; and increased gas activities and wind generation at PPM. These increases were partly offset by the favourable US dollar translation impact. Transmission and distribution costs increased by £8 million to £164 million for the quarter and by £53 million to £460 million for the nine months, as a result of higher UK Division costs associated with customer growth and higher PacifiCorp costs associated with increased maintenance and plant repair expenditure, partly offset by the favourable US dollar translation impact. Administrative expenses (including goodwill amortisation) increased by £37 million to £150 million for the quarter and by £28 million to £446 million for the nine months. The increase was due to higher labour-related costs in the US to support customer growth in PacifiCorp and business growth in PPM; increased customer capture and energy efficiency costs in the UK Division as a result of customer growth; and operating costs associated with Damhead Creek. Partly offsetting this was the release of an environmental provision within PacifiCorp and the favourable US dollar translation impact. Depreciation, which is included within each of the three preceding cost categories, was £14 million higher than the nine months to December 2003 at £342 million. Increased levels of capital investment throughout the group resulted in higher depreciation charges, partly offset by the impact of the weaker dollar.

As shown in Table 1, group operating profit improved by £19 million in the quarter, and, excluding goodwill amortisation, was higher by £16 million at £327 million*, after an adverse foreign exchange effect of £10 million. The group benefited from a £9 million gain on the disposal of SP Gas transportation and metering assets in December 2004. Group operating profit for the nine months improved by £38 million to £769 million and, excluding goodwill amortisation, was £29 million higher at £858 million*, after an adverse foreign exchange effect of £26 million. The strong performance in our UK operations and good

*	Non-GAAP performance measure (see “Cautionary Statement Regarding Non-GAAP Financial Information” above).

growth in PPM has continued and together this has more than offset PacifiCorp’s performance, which was affected by reduced thermal availability in the first six months and unfavourable weather conditions.

The net interest charge reduced by £6 million in the quarter to £50 million and by £40 million to £141 million for the nine months. The charge for the nine months included a £13 million translation benefit from the weaker US dollar and an additional £34 million benefit from the UK/US interest rate differential arising from our dollar balance sheet hedging strategy, which has been locked into for periods of up to two years. The charge also benefited from £9 million net interest receipts following the settlement of outstanding tax claims, which was offset mainly by higher interest payments on floating rate debt.

Profit before tax, as shown in Table 1, increased by £26 million to £252 million for the quarter and for the nine months was £634 million, £81 million ahead of December 2003. Excluding goodwill amortisation, profit before tax improved by £23 million to £281 million* for the quarter and by £72 million to £723 million* for the nine months, with the impact of PacifiCorp’s results being more than offset by operating profit improvements in our other businesses and the lower net interest charge. A foreign exchange hedge benefit of approximately £45 million (December 2003: £23 million) was delivered from selling forward our forecast dollar earnings at a favourable rate compared to the average rate for the period. This helps protect group profit from the effect of the weaker US dollar. Last year, the hedge benefit was significantly weighted towards the fourth quarter of the year. Although we expect our earnings for the remainder of the financial year to continue to benefit from our hedging programme, the majority of the hedge benefit has now been recognised. The hedge translation rate for the year is expected to be in the range $1.50 - $1.55.

The effective rate of tax, as shown in Table 2, is calculated by dividing the tax charge by profit before tax, expressed as a percentage. In line with last year’s results for the nine months, the effective rate of tax, excluding goodwill amortisation, has remained at 27%*. The effective rate of tax was lower than the standard rate, as it benefited from the release of provisions relating to prior years following agreement of specific items with tax authorities, the group’s financing arrangements and tax credits from US wind generation. The effective rate of tax on profit before tax was 31%, marginally lower than the equivalent period last year.


Table 2 – Effective rate of tax (£m / %)

	Nine Months 2004/05	Nine Months 2003/04

Tax charge	195.2	175.9

Profit before tax	634.2	552.8
Goodwill amortisation	88.8	98.5
Profit before tax excluding goodwill*	723.0	651.3

Effective rate of tax	30.8%	31.8%
Effective rate of tax excluding goodwill*	27.0%	27.0%

Earnings per share, as shown in Table 1, improved by 1.05 pence to 9.53 pence for the quarter and by 3.34 pence to 23.73 pence for the nine months. Excluding goodwill

*	Non-GAAP performance measure (see “Cautionary Statement Regarding Non-GAAP Financial Information” above).

amortisation, earnings per share improved by 0.90 pence to 11.11 pence* for the quarter and by 2.81 pence to 28.58 pence* for the nine months.

The dividend for the third quarter of 2004/05, as previously indicated, will be 4.95 pence per share, an increase of 4.2% on the prior year, payable on 29 March 2005. The ADS dividend will be $0.3676 per ADS. This takes the total dividend for the first nine months of the year to 14.85 pence per share, with the balance of the total dividend to be set in the fourth quarter. We remain committed to our aim to grow dividends broadly in line with earnings.

Investment

Our net capital investment for the nine months was £1,048 million, with £682 million (65%) invested for growth and £366 million invested in refurbishment, upgrade and other projects. Growth investment included the acquisitions in the UK of the 800 MW Damhead Creek power plant for £320 million and the remaining 50% of the 400 MW Brighton power plant for £72 million. Other growth investment totalled £290 million and included windfarm development spend of £83 million in the UK and the US, network expansion and reinforcement spend of £117 million in the UK and US and the ongoing construction of the 525 MW Currant Creek power plant in Utah. Investments in our regulated businesses aim to achieve at least the allowed rate of regulatory returns.

Further information on investment is given within the “Business Reviews” below.

Business Reviews

PacifiCorp

PacifiCorp’s turnover for the quarter to December 2004 was £19 million higher than the equivalent period last year at £564 million and for the nine months was £43 million lower at £1,724 million. The weaker US dollar adversely impacted sterling turnover by £45 million for the quarter and by £160 million for the nine months. Dollar turnover increased by 13% for the quarter mainly due to higher wholesale volumes, customer growth and increased customer usage, as retail sales volumes increased by 2% compared to the third quarter to December 2003. In the nine months, dollar turnover increased by 8% due mainly to higher wholesale revenue volume growth associated with energy balancing (which was offset by corresponding increases in purchase costs). Retail revenues for the nine months were higher than the equivalent period last year primarily as a result of rate increases partly offset by a reduction in the recovery of deferred power costs. Volume benefits from customer growth were offset by lower than average customer usage, due mainly to milder weather.

PacifiCorp’s operating profit for the quarter, as shown in Table 3, reduced by £5 million to £109 million and, excluding goodwill amortisation, fell by £7 million to £137 million*, with a £10 million unfavourable net translation variance arising from the weaker US dollar. Dollar operating profit, excluding goodwill amortisation, increased by $5 million to $237 million*, with higher retail and other regulatory revenues contributing $19 million of this increase and efficiency initiatives adding a further $6 million. Net power costs increased by $21 million as the 5% improvement in thermal generation output was more than offset by higher market prices and increased purchases to meet a 2% rise in retail demand. Other net revenue and cost movements were favourable by $1 million.

*	Non-GAAP performance measure (see “Cautionary Statement Regarding Non-GAAP Financial Information” above).

For the nine months, operating profit was £320 million, £48 million lower than December 2003 and, excluding goodwill amortisation, was lower by £58 million at £405 million* (down $55 million to $667 million*). This reduction included a net £28 million adverse translation impact from the weaker US dollar.


Table 3 – PacifiCorp (£m)

Quarter 3			Nine Months
2004/05	2003/04		2004/05	2003/04

108.9	113.7	Operating profit	319.8	367.8
27.7	30.3	Goodwill amortisation	84.8	94.4
136.6	144.0	Operating profit excluding goodwill*	404.6	462.2

Retail and other regulatory revenues grew by $71 million before taking account of, as expected, the reduction in deferred power cost recoveries of $36 million. Underlying revenue growth reflected regulatory rate increases and customer growth, partly offset by lower customer usage, mainly as a result of the milder weather.

Net power costs increased by $91 million, including the impact of lower thermal generation availability in the first six months and the related increase in short-term purchase volumes. Higher market prices in general and increased load volumes in the quarter also contributed to the rise in net power costs. In addition, output from our hydro facilities decreased by 5% for the nine months primarily as a result of continuing unfavourable weather conditions.

Operating efficiency initiatives delivered $29 million of benefits in the nine months and the total efficiencies delivered to date now exceeds our $300 million benefits target. Other net revenue and cost movements were adverse by $63 million as labour-related and servicing costs required to support customer growth, depreciation and maintenance and plant repair expenditure increased. As reported at the half year, a $56 million environmental liability provision was released following completion of a detailed study. This compares to provisions released and miscellaneous income recognised of $21 million in the prior year.

PacifiCorp’s net capital investment for the nine months was £320 million, including £159 million (50%) for organic growth. Of this, £80 million was invested in the new plant at Currant Creek and £79 million in new connections, network reinforcement and other spend, including our ongoing network expansion project along the Wasatch Front in Utah.

Excellent progress has been made in our Multi-State Process (“MSP”), with the Utah Public Service Commission’s approval in December and the Oregon Public Utility Commission’s approval in January. This means that states representing around 83% of PacifiCorp’s revenues now have a common methodology on cost and investment allocation. An order from the Idaho Public Utilities Commission is expected shortly.

PacifiCorp filed two general rate case requests recently. The first, on 12 November 2004 with Oregon for approximately $102 million, related to increases in operating costs, purchased power, pension and other employee benefit costs. The second, on 14 January 2005 with Idaho for approximately $15 million, related to increases in operating costs. Both of these requests are expected to be resolved by September 2005. PacifiCorp’s Utah general rate case request is continuing on schedule requesting approximately $96 million as adjusted for actual results that differed from the original request of $111 million, with resolution expected by April 2005 and settlement discussions are ongoing with all parties. PacifiCorp is also

*	Non-GAAP performance measure (see “Cautionary Statement Regarding Non-GAAP Financial Information” above).

seeking recovery of costs related to unfavourable weather conditions with regulators in Oregon through deferral requests or other regulatory approaches.

In November, PacifiCorp signed a 50-year Lewis River hydroelectric settlement along with representatives of more than 25 state, county and federal agencies, environmental and citizen groups and Native American tribes. Seven out of nine similar hydroelectric agreements in PacifiCorp’s area have now been signed, representing agreement with various interested parties, including diverse special interest groups.

Infrastructure Division

Infrastructure Division’s external turnover increased by £8 million (8%) to £101 million for the quarter and by £28 million (11%) to £279 million for the nine months, primarily due to higher regulated and new connections business revenues, both driven by higher volumes.

Infrastructure Division’s operating profit rose by £7 million to £120 million for the quarter due to a £3 million increase in regulated revenues and the Division’s £5 million share of the gain on disposal of gas assets during December 2004, as part of our continued focus on core activities, partly offset by a £1 million increase in net costs. For the nine months, operating profit increased by £22 million to £313 million. Regulated revenues improved by £14 million, due to higher distribution sales volumes and favourable transmission prices, in line with allowed revenues. Net costs and other income were favourable by £8 million, as higher rates and depreciation costs of £7 million were more than offset by lower net operating expenses and one-off gains.


Table 4 – Infrastructure Division (£m)

Quarter 3			Nine Months
2004/05	2003/04		2004/05	2003/04

120.0	112.6	Operating profit	313.1	291.2

Infrastructure Division’s net capital investment for the nine months totalled £200 million, with £54 million (27%) invested for organic growth, including expenditure on the connection to the new Black Law windfarm. Other organic investment included new customer connections and the Liverpool city centre reinforcement project. Following Ofgem’s proposal to grant funding of £190 million for investment required to accommodate renewable generation in Scotland, the first stage of the procurement and contract allocation process was completed at the end of December 2004 with the project expected to be concluded by autumn 2009.

In December, we accepted Ofgem’s electricity distribution price control proposal, which will apply to our distribution businesses over the next five years from 1 April 2005. Our transmission business also accepted the extension of Ofgem’s price control for the next two years from 1 April 2005. These price review outcomes are the result of working closely and constructively with Ofgem to reach agreement. They present challenges for the businesses as well as opportunities to enhance returns through the revised package of incentive mechanisms. Overall, regulated revenues will increase in the future, reflecting the investment focus of the reviews.

We have also worked closely with Ofgem to reach agreement on funding relating to Transmission Investment for Renewable Generation. We are pleased to note that Ofgem

agrees with the need to move ahead with the first phase of our investments totalling £190 million. We also embarked on a £30 million upgrade of the electricity network in Liverpool as the city prepares to be European Capital of Culture in 2008.

UK Division

UK Division’s turnover grew by £246 million (31%) in the quarter and by £720 million (40%) for the nine months to £1,052 million and £2,529 million respectively, due to a number of factors. Strong volume growth in electricity and gas turnover was experienced as a result of customer gains particularly within the domestic gas and out-of-area electricity markets. Volumes of wholesale electricity sales in England & Wales increased which, as part of the Division’s energy balancing activities, were offset by increases in purchase costs. The recent Damhead Creek acquisition also contributed significantly to turnover volume growth. Turnover benefited to a lesser extent by increased prices in both wholesale and domestic retail activities.

Driven by continued customer growth and investment in generation, the UK Division maintained its strong performance, with operating profit, as shown in Table 5, improved by £14 million in the quarter to £56 million and, excluding goodwill amortisation, to £57 million*. We attracted an average of 100,000 new customers per month to break through the five million level, an increase of one million customers (25%) in 12 months. This success is largely due to our innovative product offerings as well as the breadth of our sales channels.

Operating profit improved by £53 million for the nine months to £100 million and, excluding goodwill amortisation, to £104 million*. Electricity and gas margins improved by £129 million. Customer growth, backed by our investment in generation, delivered £95 million of this increase. The effective management of our generation resource portfolio, including the benefit of our rolling commodity procurement strategy, contributed a further £34 million. The substantial growth in customer numbers contributed to higher customer capture, energy efficiency and customer service costs of £40 million, and other net costs increased by £40 million, including £20 million of operating expenses relating to Damhead Creek and Brighton. The UK Division benefited by £4 million from the gain on disposal of gas metering assets.


Table 5 – UK Division (£m)

Quarter 3			Nine Months
2004/05	2003/04		2004/05	2003/04

56.1	42.4	Operating profit	100.3	47.0
1.2	1.2	Goodwill amortisation	3.6	3.6
57.3	43.6	Operating profit excluding goodwill*	103.9	50.6

UK Division’s net capital investment for the nine months of £482 million included £427 million (89%) invested for growth, primarily as a result of the Damhead Creek and Brighton power plant acquisitions. Other growth expenditure included investment in our Black Law windfarm development, which is scheduled to start generating in spring 2005. Our salt-cavern natural gas storage project at Byley, Cheshire, has been given the final go-ahead and we are taking forward the development of the project.

The energy requirements of our increasing customer numbers are balanced by our flexible generating plant portfolio, including our most recent acquisitions, Damhead Creek and the remaining 50% ownership of the Brighton plant. Combined with our rolling, forward

*	Non-GAAP performance measure (see “Cautionary Statement Regarding Non-GAAP Financial Information” above).

purchasing strategy for gas and coal, this helps cushion the impact of increasing wholesale market prices in the year and smoothes out volatility.

In January 2005, a new customer service centre facility was opened near Hamilton in Lanarkshire, creating 150 jobs to help meet the rapid growth in customer demand. Our 6 Sigma business transformation programme further improved our customer processes, and delivered revenue and cost benefits of £8 million for the nine months.

PPM

Turnover for PPM increased by £60 million to £140 million for the quarter and by £157 million to £380 million for the nine months, after the adverse impact of the weaker US dollar of £6 million and £18 million, respectively. Dollar turnover improved by $123 million (90%) in the quarter and by $321 million (87%) for the nine months. The growth in turnover was principally volume related and was due to energy management activities on contract storage and energy positions, increased revenues from new wind resources and gas storage facilities at Katy and Alberta.

PPM’s operating profit, including and excluding goodwill amortisation, as shown in Table 6, rose by £2 million to £13 million* for the quarter (by $5 million to $23 million*) from new wind resources, gas storage facilities and improved energy management activities on contract storage and energy positions, partially offset by higher operating costs.

For the nine months, operating profit increased by £11 million to £36 million and, excluding goodwill amortisation, to £37 million* (by $17 million to $59 million*). The contribution from wind resources improved by $13 million and gas storage facilities at Katy and Alberta contributed an additional $7 million – a strong performance, which we expect to continue for the remainder of the year. Energy management activities, including benefits arising from contract storage and energy positions, improved by $17 million. Net operating costs required to support increased business activities and infrastructure were higher by $15 million and depreciation increased by $5 million.


Table 6 – PPM (£m)

Quarter 3			Nine Months
2004/05	2003/04		2004/05	2003/04

12.7	10.3	Operating profit	36.3	25.1
0.1	0.2	Goodwill amortisation	0.4	0.5
12.8	10.5	Operating profit excluding goodwill*	36.7	25.6

PPM’s net capital investment for the nine months was £46 million, with £42 million (91%) of this invested for growth, primarily on new wind generation projects including the 75 MW Klondike II windfarm in Oregon and the 100 MW Trimont windfarm in Minnesota, both with long-term contracts in place for their output. PPM also announced plans to build the new 150 MW Elk River windfarm in Kansas and has signed a 20-year contract for the output with a regional utility. This brings the total windfarm projects announced to date for 2005 to 325 MW and will bring the total renewable generation under PPM’s control to 1,156 MW, with 91% of PPM’s windfarm output committed under long-term contract. During the quarter, PPM acquired the northeastern US wind energy developer, Atlantic Renewable Energy Corporation, which has over 500 MW of wind projects in the northeast US that are planned to

*	Non-GAAP performance measure (see “Cautionary Statement Regarding Non-GAAP Financial Information” above).

be operational between 2005 and 2010.

Net Assets

Prior year net assets have been restated for the impact of the Urgent Issues Task Force Abstract 38 ‘Accounting for ESOP trusts’, which requires the group’s own shares held under trust to be deducted in arriving at shareholders’ funds.

Group net assets increased by £158 million (3%) from £4,752 million to £4,910 million in the nine months compared to the year end position at 31 March 2004, primarily as a result of retained profit, with our balance sheet hedging strategy offsetting the impact of exchange movements on translation of our US results and net assets.

Tangible fixed assets increased following a significant level of organic investment in our existing asset base and the acquisition of the Damhead Creek and Brighton power plants. This increase was partly offset by foreign exchange movements due to the weaker dollar and depreciation charged to the profit and loss account.

Stocks were higher than March 2004 mainly due to increased UK Division coal stocks and PPM gas stocks, whilst the increase in debtors is principally due to higher customer numbers in UK Division and contract gas activities within PPM. Higher interest and tax creditors, increased contract gas accruals in PPM and energy accruals in UK Division were the main reasons for the increase in creditors since March 2004.

The increase in debt is discussed in Section 3 “Liquidity and Capital Resources”.

3. Liquidity and Capital Resources

For the nine months to December 2004, the treasury focus continued to be to minimise interest costs and effectively manage both foreign exchange and interest rate risk. The group continued to ensure that borrowings were financed from a variety of competitive sources and that committed facilities were 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 while avoiding excessive credit risk.

Interest

The group interest charge as discussed in the “Financial Overview” above, continued to benefit from our dollar balance sheet hedging strategy whereby the group swaps out of sterling liabilities into dollar liabilities to hedge its US dollar denominated net assets. This also gives rise to the group paying interest in dollars and receiving interest in sterling, thereby benefiting as US interest rates were below those in the UK.

The group also continued to fix a percentage of its net borrowings for periods of more than one year. In accordance with the group’s interest policy, the group is moving towards its target of a long-term benchmark of 70% fixed rate and 30% floating rate interest. As at 31 December 2004, 75% of debt has interest fixed for a period of more than one year.

Balance Sheet Hedging

The group has currently hedged $6,200 million (March 2004: $5,900 million), representing 94% of its US net assets. In addition to the $700 million convertible bonds issued during last year, liabilities have been created for periods out to March 2012, by means of cross-currency swaps totalling $5,500 million. The increase in the nine months to December 2004 was to cover increases in the value of US net assets. Maturing swaps have been renewed and new swaps put in place with maturities of 2007 and 2008.

Cash Flow and Net Debt

Cash flows from operating activities reduced compared to the prior nine months to December 2003 by £228 million to £676 million, as improved operating profit included higher provision movements (relating mainly to the utilisation of onerous energy purchase contracts within the UK Division and the release of the environmental provision in PacifiCorp); and working capital requirements increased primarily due to customer growth in the UK Division and increased contract gas storage activities within PPM, both of which have and will continue to benefit performance this year. Interest, tax and dividend payments totalled £384 million, with the tax and interest payments substantially lower than last year due to the settlement of outstanding tax claims and cash benefits associated with our hedging strategy. Net inflows from the sale of tangible fixed assets and fixed asset investments were £32 million. Financing net inflows, other than changes in net debt, were £87 million, mainly as a result of cash received on the maturing of net investment hedging derivatives, during the first half of the year. These cash flows combined provided cash of £411 million which contributed to the group’s net capital investment cash spend of £982 million. After adverse non-cash movements of £33 million, which included debt acquired following the purchase of the remaining 50% of Brighton power plant partly offset by the favourable effect of foreign exchange, net debt at 31 December 2004 was £4,329 million, £604 million higher than at 31 March 2004. Gearing (net debt/equity shareholders’ funds) was 89%, compared to 79% as at 31 March 2004.

Included in net debt are short-term bank and other deposits of £672 million, down £675 million from March 2004 principally as a result of the £320 million acquisition of Damhead Creek, the repayment of the £116 million debt acquired with the Brighton power plant and other cash utilised to fund business operations, including our net capital organic growth cash expenditure. Cash generated from operations of £676 million and the £95 million proceeds from the maturity of net investment hedge derivatives funded our net capital refurbishment cash expenditure of £374 million and interest, tax and dividend payments of £384 million. Total debt balances marginally reduced from £5,072 million at March 2004 to £5,001 million at December 2004 mainly due to favourable foreign exchange movements of £97 million, partly offset by non-cash movements of £12 million and a £14 million net drawdown of borrowings.

In addition to the cash generated from operations and existing cash balances, the group relies on flexible borrowing facilities from the capital markets, which are 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.

Financing

The group’s external borrowings have generally been sourced in two separate pools. In the UK, Scottish Power UK plc has been the finance vehicle for the majority of the UK activities. In the US, predominantly all of the debt is issued by PacifiCorp, the regulated utility, and is entirely denominated in US dollars.

Scottish Power plc and PacifiCorp have both renewed maturing bank facilities, $375 million and $800 million respectively, with the facilities now maturing in 2008 and 2007. During August 2004 PacifiCorp issued two series of first mortgage bonds of $200 million each with maturities of 2014 and 2034.

4. Quantitative and Qualitative Disclosures about Market Risk

Market Rate Sensitive Instruments and Risk Management

The group uses interest rate swaps, forward foreign exchange contracts and other financially settled derivative instruments to manage the primary market exposures associated with the underlying assets, liabilities and committed transactions. Financially settled “weather” derivatives are used to manage risk created by varying weather circumstances affecting commodity demand and operations. The group also uses commodity transactions and commodity derivatives (that can be settled financially or by delivery of the physical commodity) to further manage its commodity price and volumetric risks. These instruments are employed to reduce risk by creating offsetting financial positions or by directly hedging such commodity exposures.

Such physically or financially settled instruments held by the group match offsetting physical transactions and are not held for financial trading purposes. Exceptions to this exist in the group’s competitive divisions (PPM and the UK Division) where, subject to risk management controls, a limited and controlled number of transactions and derivatives may be held for proprietary trading purposes. In addition, weather derivatives are not held for proprietary trading purposes. Subject to risk management controls, we may enter into financial transactions that are designed to reduce earnings volatility and improve the return on assets and are structured around the physical assets of the group. ScottishPower Energy Management (Agency) Limited is authorised by the UK Financial Services Authority to undertake investment activity in the energy markets as an Energy Market Participant.

Risk Management

The principal financial risks faced by the group are energy price risk, energy volumetric risk (created by varying demand due to weather and economic circumstances and varying supply due to forced outages or other physical supply and logistics limitations), credit risk, interest rate risk, inflation rate risk, insurance risk, foreign exchange risk, liquidity risk and derivative risk. The Board has reviewed and agreed policies for managing each of these risks. To mitigate the financial risks identified, the Board has endorsed the use of certain derivative financial instruments including swaps (both interest rate and cross-currency), swaptions, options (both physically and financially settled), forward-rate agreements, financial and commodity forward contracts, commodity futures, commodity options and weather derivatives.

Information on group financial and business risk and how it is managed is provided within our Form 20-F for the year 31 March 2004, filed with the US Securities Exchange Commission. Below, we have provided an update on the group’s risk management activities, concentrating on relevant measures of risk during the nine month period to 31 December 2004.

Energy Price and Volume Risk Management

Market exposures are quantified and controlled using a number of different risk measures. These include the Value-at-Risk (“VaR”) method for earnings volatility and control. VaR is a statistically based measure of the potential financial loss on the value of a position subject to commodity price exposure over a defined period to a given level of confidence. The group’s VaR computations for its energy commodity portfolios are based on a historical simulation technique and utilise several key assumptions, including a 99% confidence level for the resultant price changes and a holding period of five business days. VaR represents an estimate of reasonably possible changes in fair value that would be measured on its portfolio assuming hypothetical movements in future market rates. VaR, while sensitive to volume portfolio changes, does not account for commodity volume risk. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to differ from predicted limits. Commodity price exposure is defined as the possibility that a change in market prices will alter the proceeds of sales or the costs of purchases as position imbalances are settled at delivery. 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.

UK Division

At 31 December 2004, the UK Division’s estimated potential five-day unfavourable impact on fair value of the energy commodity portfolio (VaR) over the next 24 months was £10.5 million, as measured by the VaR computations, compared to £10.1 million at 31 December 2003. The average daily VaR (five-day holding) for the nine months to 31 December 2004 was £7.5 million. The maximum and minimum VaR measured during the nine months to 31 December 2004 were £12.7 million and £4.2 million, respectively.

PacifiCorp

At 31 December 2004, PacifiCorp’s estimated potential five-day unfavourable impact on fair value of the natural gas and electricity commodity portfolio (VaR) over the next 24 months was £16.4 million, as measured by the VaR computations, compared to £12.2 million at 31 December 2003. The average daily VaR (five-day holding) for the nine months to 31 December 2004 was £10.1 million. The maximum and minimum VaR measured during the nine months to 31 December 2004 were £16.4 million and £7.0 million, respectively.

PPM

At 31 December 2004, PPM’s estimated potential five-day unfavourable impact on fair value of the energy commodity portfolio (VaR) over the next 24 months was £4.7 million, as measured by the VaR computations, compared to £2.2 million at 31 December 2003. The average daily VaR (five-day holding) for the nine months to 31 December 2004 was £4.7 million. The maximum and minimum VaR measured during the nine months to 31 December 2004 were £7.5 million and £1.2 million, respectively.

Insurance Risk Management

In the past nine months, the upward pressure on insurance costs experienced since 2002 has continued to ease. Although some classes of insurance are still increasing in cost, the group has worked closely with its insurance advisors and other relevant parties, including regulators, to develop initiatives designed to bring both improved efficiency and long-term stability to these costs. The renewal of the group’s main insurance policies for 2005/06 is expected to continue the 2004/05 good premium result.

Derivative Risk Management

During the nine months to December 2004, several cross-currency swaps and foreign exchange forwards hedging the US dollar net assets matured and were replaced with new cross-currency swaps, resulting in cash receipts of £95 million. These cash receipts result from the weakness of the US dollar since the hedges were put in place. A prolonged period of relative US dollar strength would result in the payment of cash to counterparties, to the extent that the derivatives had not been replaced by primary dollar debt.

5. Critical Accounting Policies

The group’s Accounts are prepared in accordance with UK GAAP. Certain of the group’s accounting policies have been identified as critical accounting policies by identifying which policies involve particularly complex or subjective decisions or assessments. The UK GAAP accounting policies that have been identified as critical are turnover, environmental provisions, decommissioning and mine reclamation provisions, tax, provisions and contingencies, and pensions and other post-retirement benefits. In addition to preparing the group’s Accounts in accordance with UK GAAP the directors are also required to prepare a reconciliation of the group’s profit or loss and shareholders’ funds between UK GAAP and US GAAP. Certain of the group’s US GAAP accounting policies have been identified as critical US GAAP accounting policies. These policies relate to US regulatory assets, impairment of goodwill, derivative financial instruments, and pensions and other post-retirement benefits. The group’s critical accounting policies under both UK GAAP and US GAAP are described in the group’s Annual Report and Accounts on Form 20-F for the year ended 31 March 2004.

6. Accounting Developments

There have been no material changes to the group’s UK GAAP accounting policies in the nine months ended 31 December 2004. The UK Accounting Standards Board has issued a number of accounting standards that will apply in 2005/06 and beyond to companies complying with UK GAAP. However, as the group is required to prepare its Accounts in accordance with International Financial Reporting Standards (“IFRS”) for the financial year commencing 1 April 2005, these accounting standards will have no impact on the group’s Accounts in future years. The potential impact of IFRS on the group was described in the group’s Annual Report and Accounts on Form 20-F for the year ended 31 March 2004. The group remains on track to commence reporting its Accounts in accordance with IFRS with effect from 1 April 2005.

There have been no material changes to the group’s US GAAP accounting policies in the nine months ended 31 December 2004. In May 2004, the Financial Accounting Standards Board (“FASB”) released FASB Staff Position No. 106-2, ‘Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003’ (“FASB SP No. 106-2”). FASB SP No. 106-2 provides guidance on the accounting for the effects of the Medicare Act for employers that sponsor post-retirement health care plans that offer prescription drug benefits and required employers to disclose the effect of the federal subsidy afforded by the Medicare Act. For entities that elected deferral under FASB Staff Position No. 106-1, ‘Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003’ (“FASB SP No. 106-1”), and for which the impact is significant, FASB SP No. 106-2 was effective for the first interim period or annual period beginning after 15 June 2004. When FASB SP No. 106-2 became effective, it superseded FASB SP No. 106-1. Adopting FASB SP No. 106-2 did not have a material impact on the group’s results and financial position under US GAAP.

In June 2004, the Emerging Issues Task Force (“EITF”) issued EITF No. 03-1, ‘The meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments’ (“EITF No. 03-1”). Application guidance in EITF No. 03-1 should be used to determine whether an investment is considered impaired, whether an impairment is other than temporary, and the measurement of any such impairment. The guidance also includes accounting and disclosure considerations. In September 2004, the FASB issued FASB EITF No. 03-1-1, ‘Effective date of paragraphs 10-20 of EITF No. 03-1, The meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments’ (“FASB EITF No. 03-1-1”). FASB EITF No. 03-1-1 delayed the previously required effective date of 1 July 2004 for the group regarding the measurement and recognition guidance contained in the applicable paragraphs. The delay of the effective date is likely to be superseded with the final issuance of a FASB Staff Position on other-than-temporary impairments of investments. The adoption of the measurement and recognition guidance of EITF No. 03-1, if implemented in its present form, is not anticipated to have a material impact on the group’s results and financial position under US GAAP.

In November 2004, the FASB issued Statement of Financial Accounting Standard No. 151, ‘Inventory Costs’ (“FAS 151”). FAS 151 requires that abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage) be included as current-period charges, eliminating the option for capitalization. This statement is effective for inventory costs incurred after 1 April 2006. This statement is not expected to have a material impact on the group’s results and financial position under US GAAP.

In December 2004, the FASB issued FAS 153, ‘Exchanges of Non-monetary Assets’ (“FAS 153”), which amends Accounting Principles Board (“APB”) Opinion No. 29, ‘Accounting for Non-monetary Transactions’ (“APB No. 29”). FAS 153 eliminates the exception from fair value measurement for non-monetary exchanges of similar productive assets in APB No. 29 and replaces it with an exception for exchanges that do not have commercial substance. This statement specifies that a non-monetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. This statement is effective for any exchanges of non-monetary assets that occur after 1 April 2006. This statement is not expected to have a material impact on the group’s results and financial position under US GAAP.

In December 2004, the FASB issued FAS 123R, ‘Share-Based Payment’ (“FAS 123R”), a revision of the originally issued FAS 123. FAS 123R establishes standards for the accounting

for transactions in which an entity exchanges its equity instruments for goods or services. This statement requires that the cost resulting from all share-based payment transactions be recognised in the financial statements using the fair value method. The intrinsic value method of accounting established by APB No. 25, ‘Accounting for Stock Issued to Employees’ will no longer be allowed. This statement is effective as of the beginning of the first interim reporting period that begins after 15 June 2005. A modified prospective application is required for new awards and to awards modified, repurchased, or cancelled after the required effective date. The adoption of this statement is not expected to have a material impact on the group’s results and financial position under US GAAP.

In December 2004, the FASB issued FASB Staff Position No. 109-1, ‘Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004’ (“FASB SP No. 109-1”). This tax deduction will be treated as a “special deduction” as described in FAS 109, ‘Accounting for Income Taxes’. As such, the special deduction has no effect on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction will be reported in the period in which the deduction could be claimed on a separate return basis in accordance with the group’s accounting policy. FASB SP No. 109-1 became effective upon issuance. The impact of the deduction to the group will depend on the application of forthcoming guidance from the Internal Revenue Service and therefore the group continues to evaluate the effect that FASB SP No. 109-1 will have on its results and financial position under US GAAP.

7. Safe Harbor

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.

We wish 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. Important factors that may cause results to differ from expectations include, for example:

•

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 general rate cases and other proceedings conducted by regulatory commissions;

•

the cost, feasibility and eventual outcome of hydroelectric facility 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;

•

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;

•

the success of reorganizational and cost-saving efforts;

•

Timely and appropriate completion of the Request for Proposals process, 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.

We undertake no obligation to revise any forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting such forward-looking statements or if we later become aware that these assumptions are not likely to be achieved.

Group Profit and Loss Account


		Unaudited
		Three months ended 31 December				Nine months ended 31 December
	Notes	2004 £m		2003 £m		2004 £m		2003 £m
Turnover: group and share of joint ventures and associates		1,860.9		1,529.4		4,935.5		4,069.8
Less: share of turnover in joint ventures		(3.7	)	(5.2	)	(23.7	)	(20.1	)
Less: share of turnover in associates		(0.3	)	(0.2	)	(0.8	)	(0.5	)

Group turnover	2	1,856.9		1,524.0		4,911.0		4,049.2
Cost of sales		(1,254.4	)	(982.1	)	(3,255.1	)	(2,509.6	)

Gross profit		602.5		541.9		1,655.9		1,539.6
Transmission and distribution costs		(164.1	)	(155.8	)	(460.1	)	(407.1	)
Administrative expenses (including goodwill amortisation)		(149.7	)	(112.8	)	(446.3	)	(418.7	)
Other operating income		9.0		5.7		20.0		17.3

Operating profit	2	297.7		279.0		769.5		731.1
Share of operating profit in joint ventures		1.2		2.8		2.1		2.3
Share of operating profit in associates		3.5		—		3.6		0.1

Profit on ordinary activities before interest		302.4		281.8		775.2		733.5
Net interest and similar charges
– Group		(49.8	)	(54.2	)	(137.3	)	(176.7	)
– Joint ventures		(0.3	)	(1.4	)	(3.7	)	(4.0	)

		(50.1	)	(55.6	)	(141.0	)	(180.7	)

Profit on ordinary activities before taxation		252.3		226.2		634.2		552.8
Taxation	3	(75.9	)	(69.7	)	(195.2	)	(175.9	)

Profit after taxation		176.4		156.5		439.0		376.9
Minority interests (including non-equity)		(2.0	)	(1.4	)	(4.6	)	(4.0	)

Profit for the period		174.4		155.1		434.4		372.9
Dividends	5	(91.1	)	(87.3	)	(273.2	)	(262.2	)

Profit retained		83.3		67.8		161.2		110.7

Earnings per ordinary share	4	9.53	p	8.48	p	23.73	p	20.39	p

Diluted earnings per ordinary share	4	9.16	p	8.20	p	22.97	p	20.08	p

Dividends per ordinary share	5	4.95	p	4.75	p	14.85	p	14.25	p

The above results relate to continuing operations.

The accompanying Notes are an integral part of these Accounts.

Group Cash Flow Statement

for the nine months ended 31 December 2004


	Unaudited
	Nine months ended 31 December
	2004 £m		2003 (As restated – Note 1) £m
Cash inflow from operating activities	676.1		903.7
Dividends received from joint ventures	1.6		0.3
Returns on investments and servicing of finance	(65.0	)	(153.1	)
Taxation	(25.5	)	(102.1	)
Capital expenditure and financial investment	(624.9	)	(639.0	)

Cash flow before acquisitions and disposals	(37.7	)	9.8
Acquisitions and disposals	(325.5	)	(4.9	)
Equity dividends paid	(295.0	)	(307.1	)

Cash outflow before use of liquid resources and financing	(658.2	)	(302.2	)
Management of liquid resources	223.2		(146.7	)
Financing
– Issue of ordinary share capital	18.3		8.3
– Redemption of preferred stock of PacifiCorp	(4.1	)	(4.6	)
– Maturity of net investment hedging derivatives	95.4		—
– Cancellation of swaps	—		76.1
– Net purchase of own shares held under trust	(22.6	)	(28.7	)
– (Decrease)/increase in debt	(102.2	)	436.8

	(15.2	)	487.9

(Decrease)/increase in cash in period	(450.2	)	39.0

Reconciliation of Net Cash Flow to Movement in Net Debt

for the nine months ended 31 December 2004


	Unaudited
	Nine months ended 31 December
	2004 £m		2003 £m
(Decrease)/increase in cash in period	(450.2	)	39.0
Cash outflow/(inflow) from decrease/(increase) in debt	102.2		(436.8	)
Cash (inflow)/outflow from movement in liquid resources	(223.2	)	146.7

Change in net debt resulting from cash flows	(571.2	)	(251.1	)
Net debt acquired	(116.1	)	—
Foreign exchange movement	94.8		319.0
Other non-cash movements	(11.9	)	(10.6	)

Movement in net debt in period	(604.4	)	57.3
Net debt at end of previous period	(3,724.5	)	(4,321.0	)

Net debt at end of period	(4,328.9	)	(4,263.7	)

The accompanying Notes are an integral part of these Accounts.

Group Balance Sheet

as at 31 December 2004


		Unaudited
	Notes	31 December 2004 £m		31 December 2003 (As restated – Note 1) £m		31 March 2004 £m
Fixed assets
Intangible assets		1,822.8		1,933.7		1,855.9
Tangible assets		9,354.8		8,749.8		8,756.6
Investments
– Investments in joint ventures:
Share of gross assets		66.8		165.6		180.8
Share of gross liabilities		(45.7	)	(141.9	)	(157.3	)

		21.1		23.7		23.5
– Loans to joint ventures		12.1		37.7		38.8

		33.2		61.4		62.3
– Investments in associates		5.1		2.8		2.7
– Other investments		119.2		132.4		129.8

		157.5		196.6		194.8

		11,335.1		10,880.1		10,807.3

Current assets
Stocks	7	308.9		226.4		185.5
Debtors
– Gross debtors		1,902.4		1,955.8		1,576.2
– Less non-recourse financing		(98.5	)	(129.8	)	(109.5	)

		1,803.9		1,826.0		1,466.7
Short-term bank and other deposits		671.9		833.4		1,347.3

		2,784.7		2,885.8		2,999.5

Creditors: amounts falling due within one year
Loans and other borrowings		(434.2	)	(376.4	)	(410.7	)
Other creditors		(1,866.6	)	(1,643.4	)	(1,658.7	)

		(2,300.8	)	(2,019.8	)	(2,069.4	)

Net current assets		483.9		866.0		930.1

Total assets less current liabilities		11,819.0		11,746.1		11,737.4
Creditors: amounts falling due after more than one year
Loans and other borrowings (including convertible bonds)		(4,566.6	)	(4,720.7	)	(4,661.1	)
Provisions for liabilities and charges
– Deferred tax		(1,278.3	)	(1,246.8	)	(1,242.2	)
– Other provisions		(471.9	)	(546.7	)	(504.5	)

		(1,750.2	)	(1,793.5	)	(1,746.7	)
Deferred income		(592.4	)	(576.6	)	(577.8	)

Net assets	2	4,909.8		4,655.3		4,751.8

Called up share capital	8	932.2		929.1		929.8
Share premium	8	2,291.6		2,271.6		2,275.7
Revaluation reserve	8	46.5		42.1		41.6
Capital redemption reserve	8	18.3		18.3		18.3
Merger reserve	8	406.4		406.4		406.4
Profit and loss account	8	1,157.8		925.9		1,019.1

Equity shareholders’ funds		4,852.8		4,593.4		4,690.9
Minority interests (including non-equity)		57.0		61.9		60.9

Capital employed		4,909.8		4,655.3		4,751.8

The accompanying Notes are an integral part of these Accounts.

Approved by the Board on 10 February 2005 and signed on its behalf by


Charles Miller Smith		David Nish
Chairman		Finance Director

Notes to the Quarterly Accounts (Unaudited)

for the nine months ended 31 December 2004

1 Basis of preparation

(a)

These quarterly Accounts reflect all adjustments which are, in the opinion of the directors, necessary for a fair statement of the results for the quarterly periods presented. The quarterly information has been prepared on a basis consistent with those used to prepare the 2003/04 Annual Report and Accounts.

(b)

The quarterly Accounts are unaudited. The information shown for the year ended 31 March 2004 does not constitute statutory Accounts within the meaning of Section 240 of the Companies Act 1985 and has been extracted from the full Accounts for the year ended 31 March 2004 filed with the Registrar of Companies. The report of the auditors on these Accounts was unqualified and did not contain a Statement under either Section 237(2) or Section 237(3) of the Companies Act 1985.

(c)

The group implemented UITF Abstract 38 ‘Accounting for ESOP trusts’ (“UITF 38”) in the financial year ended 31 March 2004. UITF 38 requires own shares held under trust to be deducted in arriving at shareholders’ funds. Previously own shares held under trust were presented as fixed asset investments. Consequential adjustments were also made to Other creditors and Other provisions. Comparative figures for the nine month period to 31 December 2003 have been restated in the Balance Sheet, Cash Flow Statement and related Notes.

The effect of UITF 38 on the group’s previously reported net assets is as follows:


	As at 31 December 2003
	Fixed asset investments £m		Other creditors £m		Other provisions £m		Net assets £m
As previously reported	322.4		1,655.3		554.4		4,761.5
Effect of implementing new accounting policy	(125.8	)	(11.9	)	(7.7	)	(106.2	)

As restated	196.6		1,643.4		546.7		4,655.3

(d)	The relevant exchange rates applied in the preparation of these quarterly Accounts are detailed in Note 12.

2 Segmental information

(a) Turnover by segment


			Three months ended 31 December
			Total turnover		Inter-segment turnover				External turnover
	Notes		2004 £m	2003 £m	2004 £m		2003 £m		2004 £m	2003 £m
United Kingdom
UK Division – Integrated Generation and Supply	(i	)	1,064.0	809.4	(11.8	)	(3.3	)	1,052.2	806.1
Infrastructure Division – Power Systems			194.4	184.5	(93.5	)	(91.5	)	100.9	93.0

United Kingdom total									1,153.1	899.1

United States
PacifiCorp			564.9	545.5	(0.7	)	(0.5	)	564.2	545.0
PPM			141.9	82.4	(2.3	)	(2.5	)	139.6	79.9

United States total									703.8	624.9

Total	(ii	)							1,856.9	1,524.0

			Nine months ended 31 December
			Total turnover		Inter-segment turnover				External turnover
	Notes		2004 £m	2003 £m	2004 £m		2003 £m		2004 £m	2003 £m
United Kingdom
UK Division – Integrated Generation and Supply	(i	)	2,554.2	1,827.8	(25.7	)	(19.6	)	2,528.5	1,808.2
Infrastructure Division – Power Systems			534.4	501.4	(255.6	)	(250.1	)	278.8	251.3

United Kingdom total									2,807.3	2,059.5

United States
PacifiCorp			1,726.0	1,768.4	(2.3	)	(1.6	)	1,723.7	1,766.8
PPM			387.1	230.7	(7.1	)	(7.8	)	380.0	222.9

United States total									2,103.7	1,989.7

Total	(ii	)							4,911.0	4,049.2

2 Segmental information continued

(b) Operating profit by segment


			Three months ended 31 December
	Note		Before goodwill amortisation 2004 £m	Goodwill amortisation 2004 £m		2004 £m	Before goodwill amortisation 2003 £m	Goodwill amortisation 2003 £m		2003 £m
United Kingdom
UK Division – Integrated Generation and Supply	(i	)	57.3	(1.2	)	56.1	43.6	(1.2	)	42.4
Infrastructure Division – Power Systems			120.0	—		120.0	112.6	—		112.6

United Kingdom total			177.3	(1.2	)	176.1	156.2	(1.2	)	155.0

United States
PacifiCorp			136.6	(27.7	)	108.9	144.0	(30.3	)	113.7
PPM			12.8	(0.1	)	12.7	10.5	(0.2	)	10.3

United States total			149.4	(27.8	)	121.6	154.5	(30.5	)	124.0

Total			326.7	(29.0	)	297.7	310.7	(31.7	)	279.0


			Nine months ended 31 December
	Notes		Before goodwill amortisation 2004 £m	Goodwill amortisation 2004 £m		2004 £m	Before goodwill amortisation 2003 £m	Goodwill amortisation 2003 £m		2003 £m
United Kingdom
UK Division – Integrated Generation and Supply	(i	)	103.9	(3.6	)	100.3	50.6	(3.6	)	47.0
Infrastructure Division – Power Systems			313.1	—		313.1	291.2	—		291.2

United Kingdom total			417.0	(3.6	)	413.4	341.8	(3.6	)	338.2

United States
PacifiCorp	(ii	)	404.6	(84.8	)	319.8	462.2	(94.4	)	367.8
PPM			36.7	(0.4	)	36.3	25.6	(0.5	)	25.1

United States total			441.3	(85.2	)	356.1	487.8	(94.9	)	392.9

Total			858.3	(88.8	)	769.5	829.6	(98.5	)	731.1

(i)

UK Division – Integrated Generation and Supply completed the acquisition of the Damhead Creek CCGT power plant and associated contracts on 1 June 2004 and completed the purchase of the remaining 50% of the Brighton Power Station CCGT power plant and associated contracts on 28 September 2004. The post acquisition results of the acquired businesses amounted to turnover of £50.4 million and £110.2 million and operating profit of £11.0 million and £23.5 million for the three months and nine months to December 2004, respectively.

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

(iii)

The operating profit of the PacifiCorp segment for the nine months to December 2004 included the release of a £31 million ($56 million) environmental liability provision following completion of a detailed environmental exposure study. This release was included in the operating profit of the PacifiCorp segment for the three months to September 2004.

(c) Net assets by segment


	Note		31 December 2004 £m		31 December 2003 (As restated – Note 1) £m		31 March 2004 £m
United Kingdom
UK Division – Integrated Generation and Supply			1,641.2		922.4		1,022.5
Infrastructure Division – Power Systems			2,474.1		2,323.2		2,337.4

United Kingdom total			4,115.3		3,245.6		3,359.9

United States
PacifiCorp			5,904.1		6,129.7		5,935.8
PPM			622.9		475.7		439.0

United States total			6,527.0		6,605.4		6,374.8

Total			10,642.3		9,851.0		9,734.7

Unallocated net liabilities	(i	)	(5,732.5	)	(5,195.7	)	(4,982.9	)

Total			4,909.8		4,655.3		4,751.8

(i)	Unallocated net liabilities include net debt, dividends payable, tax liabilities and investments.

3 Taxation

The charge for taxation, including deferred tax, for the nine month period ended 31 December 2004 reflects the anticipated effective rate for the year ending 31 March 2005 of 31% (year ended 31 March 2004 32%) on the profit before taxation, and includes the release of provisions of £29.9 million relating to prior years following agreement of specific items with the tax authorities during the period. The group expects that additional tax provisions will be released during the financial year ending 31 March 2005 as further settlements are reached with the tax authorities.

4 Earnings per ordinary share

Earnings per ordinary share have been calculated for all periods by dividing the profit for the period by the weighted average number of ordinary shares in issue during the period, based on the following information:


	Three months ended 31 December		Nine months ended 31 December
	2004	2003	2004	2003
Basic earnings per share
Profit for the period (£ million)	174.4	155.1	434.4	372.9
Weighted average share capital (number of shares, million)	1,830.6	1,829.0	1,830.5	1,829.3

Diluted earnings per share
Profit for the period (£ million)	176.7	157.8	442.7	377.1
Weighted average share capital (number of shares, million)	1,928.4	1,924.4	1,926.9	1,877.8

The difference between the basic and the diluted weighted average share capital is wholly attributable to outstanding share options and shares held in trust for the group’s employee share schemes and the convertible bonds.

5 Dividends per ordinary share

The third interim dividend of 4.95 pence per ordinary share is payable on 29 March 2005 to shareholders on the register at 18 February 2005. This dividend, together with the interim dividends already paid, represents total dividends of 14.85 pence per ordinary share for the nine months ended 31 December 2004. In the previous year, a third interim dividend of 4.75 pence was declared for the quarter ended 31 December 2003, representing total dividends of 14.25 pence per ordinary share for the nine months ended 31 December 2003.

6 Statement of total recognised gains and losses


	Nine months ended 31 December
	2004 £m		2003 £m
Profit for the period	434.4		372.9
Exchange movement on translation of overseas results and net assets	(123.6	)	(444.2	)
Translation differences on foreign currency hedging	170.8		386.5
Tax on translation differences on foreign currency hedging	(55.6	)	—
Revaluation reserve arising on the purchase of the remaining 50% of the Brighton Power Station	6.3		—

Total recognised gains and losses for the financial period	432.3		315.2

7 Stocks


	At 31 December		At 31 March 2004 £m
	2004 £m	2003 £m	At 31 March 2004 £m
Raw materials and consumables	129.3	140.7	91.7
Fuel stocks	173.0	73.5	88.2
Work in progress	6.6	12.2	5.6

	308.9	226.4	185.5

8 Analysis of movements in shareholders’ funds


	Number of shares 000s	Share capital £m	Share premium £m	Revaluation reserve £m		Capital redemption reserve £m	Merger reserve £m	Profit and loss account £m		Total £m
At 1 April 2004	1,859,539	929.8	2,275.7	41.6		18.3	406.4	1,019.1		4,690.9
Retained profit for the period	—	—	—	—		—	—	161.2		161.2
Share capital issued
– ESOP	2,082	1.0	7.3	—		—	—	—		8.3
– PacifiCorp Stock Incentive Plan	2,828	1.4	8.6	—		—	—	—		10.0
Consideration paid in respect of purchase of own shares held under trust	—	—	—	—		—	—	(29.7	)	(29.7	)
Credit in respect of employee share awards	—	—	—	—		—	—	7.1		7.1
Consideration received in respect of sale of own shares held under trust	—	—	—	—		—	—	7.1		7.1
Revaluation reserve arising on the purchase of the remaining 50% of the Brighton Power Station	—	—	—	6.3		—	—	—		6.3
Revaluation surplus realised	—	—	—	(1.4	)	—	—	1.4		—
Exchange movement on translation of overseas results and net assets	—	—	—	—		—	—	(123.6	)	(123.6	)
Translation differences on foreign currency hedging	—	—	—	—		—	—	170.8		170.8
Tax on translation differences on foreign currency hedging	—	—	—	—		—	—	(55.6	)	(55.6	)

Balance at 31 December 2004	1,864,449	932.2	2,291.6	46.5		18.3	406.4	1,157.8		4,852.8

9 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’)

The consolidated Accounts of the group are prepared in accordance with UK GAAP which differs in certain significant respects from US GAAP. The effect of the US GAAP adjustments to profit for the financial period and equity shareholders’ funds are set out in the tables below.


	Nine months ended 31 December
(a) Reconciliation of profit for the financial period to US GAAP:	2004 £m		2003 £m
Profit for the financial period under UK GAAP	434.4		372.9
US GAAP adjustments:
Amortisation of goodwill	88.8		98.5
US regulatory net assets	(30.9	)	(64.5	)
Pensions	7.5		(0.2	)
Depreciation on revaluation uplift	1.4		1.4
Decommissioning, environmental and mine reclamation	(39.5	)	(5.5	)
PacifiCorp Transition Plan costs	(6.2	)	(25.1	)
FAS 133	167.4		241.9
Other	(11.1	)	(5.3	)

	611.8		614.1
Deferred tax effect of US GAAP adjustments	(21.9	)	3.1

Profit for the period under US GAAP before cumulative adjustment for FAS 143	589.9		617.2
Cumulative adjustment for FAS 143	—		(0.6	)

Profit for the period under US GAAP	589.9		616.6

Earnings per share under US GAAP	32.23	p	33.71	p

Diluted earnings per share under US GAAP	30.31	p	33.06	p

The adjustment described as ‘FAS 133’ comprises FAS 133 and subsequent revising standards, FAS 138 and FAS 149, together with guidance issued by the Derivatives Implementation Group (‘DIG’).

The cumulative adjustment to the profit under US GAAP for the nine months ended 31 December 2003 of £(0.6) million (net of tax) represented the cumulative effect on US GAAP earnings of adopting FAS 143 ‘Accounting for Asset Retirement Obligations’ effective from 1 April 2003.

9 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’) continued


(b) Effect on equity shareholders’ funds of differences between UK GAAP and US GAAP:	31 December 2004 £m		31 December 2003 (As restated – Note 1) £m		31 March 2004 £m
Equity shareholders’ funds under UK GAAP	4,852.8		4,593.4		4,690.9
US GAAP adjustments:
Goodwill	572.3		572.3		572.3
Business combinations	(189.7	)	(201.1	)	(196.1	)
Amortisation of goodwill	227.7		125.9		150.0
US regulatory net assets	588.4		833.0		724.7
Pensions	(7.4	)	(394.3	)	(18.9	)
Dividends	91.1		87.3		112.9
Revaluation	(60.3	)	(54.0	)	(54.0	)
Depreciation on revaluation uplift	13.8		11.9		12.4
Decommissioning, environmental and mine reclamation	(53.7	)	(7.3	)	(14.9	)
PacifiCorp Transition Plan costs	15.5		26.8		22.2
FAS 133	182.0		102.4		2.2
ESOP shares held in trust	—		76.2		—
Other	11.3		(10.4	)	(12.9	)
Deferred tax:
Effect of US GAAP adjustments	(297.3	)	(147.6	)	(275.0	)
Effect of differences in methodology	10.7		(17.6	)	14.5

Equity shareholders’ funds under US GAAP	5,957.2		5,596.9		5,730.3

The FAS 133 adjustment represents the difference between accounting for derivatives under UK and US GAAP. FAS 133 requires all derivatives, as defined by the standard, to be marked to market value, except those which qualify for specific exemption under the standard or associated DIG guidance, for example those defined as normal purchases and normal sales. The derivatives which are marked to market value in accordance with FAS 133 include only certain of the group’s commercial contractual arrangements as many of these arrangements are outside the scope of FAS 133. In addition, the effect of these changes in the fair value of certain long-term contracts entered into to hedge PacifiCorp’s future retail energy resource requirements, which are being marked to market value in accordance with FAS 133, are subject to regulation in the US and are therefore deferred as regulatory assets or liabilities pursuant to FAS 71 ‘Accounting for the Effects of Certain Types of Regulation’. The FAS 133 adjustment included within equity shareholders’ funds at 31 December 2004 of £182.0 million includes a net liability of £146.0 million which is subject to regulation and is therefore offset by a US regulatory asset of £146.0 million included within ‘US regulatory net assets’ above.

The reconciliations of profit for the period and equity shareholders’ funds at the period end from UK GAAP to US GAAP only include those items which have a net effect on profit or equity shareholders’ funds. There are other GAAP differences, not included in the reconciliations, which would affect the classification of assets and liabilities or of income and expenditure. In addition to the reclassifications disclosed in Note 34(xv) to the 2003/04 Annual Report and Accounts, the items which would have such an effect are as follows:

(a)	under UK GAAP, debtors are presented as current assets and include amounts falling due after more than one year. Under US GAAP, debtors falling due after more than one year are included within non-current assets

(b)

under UK GAAP, preferred stock subject to mandatory redemption issued by a subsidiary and held outside the group is classified as a minority interest in the group balance sheet and dividends on such preferred stock are shown as a minority interest in the group profit and loss account. Under US GAAP, preferred stock subject to mandatory redemption issued by a subsidiary and held outside the group is classified as a liability in the balance sheet and dividends on such preferred stock are included as an interest cost in the income statement.

Additional information under US GAAP

Stock-based compensation

Under US GAAP, the group applies Accounting Principles Board Opinion No. 25, ‘Accounting for Stock Issued to Employees’ (“APB 25”), and related interpretations in accounting for its plans and a compensation expense has been recognised accordingly for its share option schemes. As the group applies APB 25 in accounting for its plans, under FAS 123, ‘Accounting for Stock-Based Compensation’ (“FAS 123”), it has adopted the disclosure only option in relation to its share option schemes. Had the group determined compensation cost based on the fair value at the grant date for its share options under FAS 123, the group’s profit for the financial period under US GAAP and earnings per share under US GAAP would have been reduced to the pro forma amounts below:


	Nine months ended 31 December
	2004		2003
Profit for the financial period under US GAAP (£ million)	589.9		616.6
Reversal of APB 25 stock compensation expense (included within the ‘Other’ adjustment) (£ million)	1.5		2.1
Stock compensation expense calculated under FAS 123 (£ million)	(3.6	)	(3.5	)

Pro forma profit for the financial period under US GAAP (£ million)	587.8		615.2

Basic earnings per share under US GAAP	32.23	p	33.71	p

Pro forma basic earnings per share under US GAAP	32.11	p	33.63	p

Diluted earnings per share under US GAAP	30.31	p	33.06	p

Pro forma diluted earnings per share under US GAAP	30.20	p	32.99	p

Pensions and other post-retirement benefits

The components of the pension and other post-retirement benefit costs for the periods ended 31 December 2004 and 2003 were as follows:


	Pension costs Nine months ended 31 December				Other post-retirement benefit costs Nine months ended 31 December
	2004 £m		2003 £m		2004 £m		2003 £m
Service cost	39.2		33.8		3.5		3.4
Interest cost	125.9		117.7		12.7		15.6
Expected return on plans’ assets	(135.2	)	(125.2	)	(10.8	)	(12.1	)
Amortisation of experience losses	15.9		19.9		2.5		3.0
Amortisation of prior service cost	(0.2	)	(0.8	)	—		—

Net periodic benefit cost	45.6		45.4		7.9		9.9

9 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’) continued

Commitments and contingencies

(i)	Environmental issues

UK businesses

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

PacifiCorp

PacifiCorp is subject to numerous environmental laws including: the Federal Clean Air Act and various state air quality laws; the Endangered Species Act, particularly as it relates to certain endangered species of fish; the Comprehensive Environmental Response, Compensation and Liability Act, and similar state laws relating to environmental cleanups; the Resource Conservation and Recovery Act, and similar laws relating to the storage and handling of hazardous materials; and the Clean Water Act and similar state laws relating to water quality. These laws could potentially impact future operations. Contingencies identified at 31 December 2004, principally consist of air quality matters. Pending or proposed air regulations will require PacifiCorp to reduce its electricity plant emissions of sulphur dioxide, nitrogen oxides and other pollutants below current levels. The reductions will be required to address regional haze programs, mercury emissions regulations and possible re-interpretations and changes to the Federal Clean Air Act. Also, similar to many other coal burning utilities, PacifiCorp has received information requests from the Environmental Protection Agency (“EPA”) related to PacifiCorp’s compliance with New Source Review provisions of the Clean Air Act, which has resulted in some discussions with the EPA and state regulatory authorities. PacifiCorp in the future may incur significant costs to comply with various tighter air emissions requirements. These potential costs are expected to consist primarily of capital expenditures. However, PacifiCorp expects these costs will be included in rates and, therefore, are not expected to have a material impact on the group’s results and financial position.

(ii)	Hydroelectric relicensing

PacifiCorp

Approximately 97% of the installed capacity of PacifiCorp’s hydroelectric portfolio is regulated by the Federal Energy Regulatory Commission through 18 individual licences. Several of PacifiCorp’s hydroelectric projects are at some stage of relicensing under the Federal Power Act. Hydroelectric relicensing and the related environmental compliance requirements are subject to uncertainties. PacifiCorp expects that future costs relating to these matters may be significant and consist primarily of additional relicensing costs, operations and maintenance expense and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. The group has accumulated approximately £12.1 million in costs at 31 December 2004 for ongoing hydroelectric relicensing that are reflected as assets within the group balance sheet.

Recent US accounting pronouncements

In May 2004, the Financial Accounting Standards Board (“FASB”) released FASB Staff Position No. 106-2, ‘Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003’ (“FASB SP No. 106-2”). FASB SP No. 106-2 provides guidance on the accounting for the effects of the Medicare Act for employers that sponsor post-retirement health care plans that offer prescription drug benefits and required employers to disclose the effect of the federal subsidy afforded by the Medicare Act. For entities that elected deferral under FASB Staff Position No. 106-1, ‘Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003’ (“FASB SP No. 106-1”), and for which the impact is significant, FASB SP No. 106-2 was effective for the first interim period or annual period beginning after 15 June 2004. When FASB SP No. 106-2 became effective, it superseded FASB SP No. 106-1. Adopting FASB SP No. 106-2 did not have a material impact on the group’s results and financial position under US GAAP.

In December 2004, the FASB issued FAS 123R, ‘Share-Based Payment’ (“FAS 123R”), a revision of the originally issued FAS 123. FAS 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. This statement requires that the cost resulting from all share-based payment transactions be recognised in the financial statements using the fair value method. The intrinsic value method of accounting established by APB No. 25, ‘Accounting for Stock Issued to Employees’ will no longer be allowed. This statement is effective as of the beginning of the first interim reporting period that begins after 15 June 2005. A modified prospective application is required for new awards and to awards modified, repurchased, or cancelled after the required effective date. The adoption of this statement is not expected to have a material impact on the group’s results and financial position under US GAAP.

10 Acquisitions

On 1 June 2004, ScottishPower completed the acquisition of the 800 MW Damhead Creek CCGT power plant and associated contracts, including the benefit of a long-term gas supply agreement, from its creditor banks for a cash consideration of £313 million excluding expenses. On 28 September 2004, ScottishPower completed the purchase of the remaining 50% of the 400 MW Brighton Power Station CCGT power plant and associated contracts, including the benefit of a long-term gas supply agreement, for a cash consideration of £26 million excluding expenses. Provisional fair values have been attributed to the assets and liabilities acquired in respect of both acquisitions. No goodwill is required to be recognised in respect of these acquisitions.

11 Contingent liabilities

Thus flotation

In November 1999, the group floated a minority stake in its internet and telecommunications business, Thus plc. This gave rise to a contingent liability to corporation tax on chargeable gains, estimated at amounts up to £570 million. On 19 March 2002, the group demerged its residual holding in Thus Group plc (the new holding company of Thus plc). The charge referred to above could still arise, in certain circumstances, before 19 March 2007. Members of the ScottishPower group have agreed to indemnify Thus Group plc for any such liability, except in circumstances arising without the consent of the ScottishPower group.

Legal proceedings

In May 2004, PacifiCorp was served with a complaint filed in the US District Court for the District of Oregon by the Klamath Tribes of Oregon, individual Klamath Tribal members and the Klamath Claims Committee. The claim generally alleges that PacifiCorp and its predecessors affected the Klamath Tribes’ federal treaty rights to fish for salmon in the headwaters of the Klamath River in southern Oregon by building dams that blocked the passage of salmon upstream to the headwaters beginning in 1911. In July 2004, PacifiCorp filed its answer to the complaint. In September 2004, the case was transferred to the Medford Division of the District of Oregon. Also in September 2004, the Klamath Tribes filed their first amended complaint adding claims of damage to their treaty rights to fish for sucker and steelhead in the headwaters of the Klamath River. The claim seeks in excess of $1.0 billion in compensatory and punitive damages. In October 2004, PacifiCorp filed its answer to the first amended complaint generally denying liability and asserting affirmative defenses for the matters alleged by the Klamath Tribes. A scheduling conference was held in October 2004, which established a procedural schedule for the case. In February 2005, PacifiCorp filed a motion for summary judgement seeking dismissal of the Klamath Tribes’ claim as untimely under the applicable statute of limitations.

The group’s businesses are parties to various other legal claims, actions and complaints, certain of which involve material amounts. Although the group is unable to predict with certainty whether or not it will ultimately be successful in these legal proceedings or, if not, what the impact might be, the directors currently believe that disposition of these matters will not have a materially adverse effect on the group’s consolidated Accounts.

12 Exchange rates

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


	Nine months ended 31 December
	2004			2003
Average rate for quarters ended
30 June	$	1.81/	£	$	1.62/	£
30 September	$	1.82/	£	$	1.61/	£
31 December	$	1.87/	£	$	1.71/	£

Closing rate as at 31 December	$	1.90/	£	$	1.79/	£

The closing rate for 31 March 2004 was $1.84/£.