Edgar Filing: SCOTTISH POWER PLC

2004/5 Half Year Results inc Q2 to September 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 December 2004

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, dated December 23, 2004, regarding 2004/05 half year results including second quarter ended September 30, 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	December 23, 2004	By:	/s/ Donald McPherson
			Donald McPherson Assistant Company Secretary

SCOTTISH POWER plc

2004/05 HALF YEAR RESULTS including 2nd Quarter to 30 September 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. This includes monthly reported actual results in our management accounts, forecasts, budgets and business plans. Therefore, to provide more meaningful information, ScottishPower has focused its discussion of business performance on the results excluding goodwill amortisation. Such non-GAAP performance measures should not be viewed as replacements for, or alternatives to, comparable GAAP measures, rather they should be considered as complementary 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. The non-GAAP performance measures included herein are among the primary indicators ScottishPower 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. Since ScottishPower has historically reported these non-GAAP performance measures to the investment community and analysts forecast the results of the group on this basis, ScottishPower believes that their inclusion provides consistency in its financial reporting.

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 second quarter and half year statutory results are presented in the “Group Profit and Loss Account” and in Note 2 “Segmental information”. Unless otherwise stated “half year” relates to the six months to 30 September 2004, and “quarter” relates to the three months to 30 September 2004.

The following discussion, which contains information updated only through 10 November 2004, 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 September 2004, served approximately 6.3 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 4.7 million customers. 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 2

Half Year

2004/05

2003/04

£m, except per share amounts

2004/05

2003/04

1,572.8

1,279.8

Turnover

3,054.1

2,525.2

251.9

219.6

Operating profit

471.8

452.1

29.8

33.5

Goodwill amortisation

59.8

66.8

281.7

253.1

Operating profit excluding goodwill*

531.6

518.9

211.5

155.9

Profit before tax

381.9

326.6

29.8

33.5

Goodwill amortisation

59.8

66.8

241.3

189.4

Profit before tax excluding goodwill*

441.7

393.4

7.91

5.65

Earnings per share (pence)

14.20

11.91

1.63

1.83

Earnings per share impact of goodwill (pence)

3.27

3.65

9.54

7.48

Earnings per share excluding goodwill (pence)*

17.47

15.56

4.95

4.75

Dividends per share (pence)

9.90

9.50

Group Profit and Loss

Group turnover increased by £293 million to £1,573 million in the quarter and by £529 million to £3,054 million for the half year to September 2004 compared to the equivalent periods last year. The weaker US dollar reduced sterling revenues of PacifiCorp and PPM by £59 million in the quarter and £128 million in the half year, which was mitigated by the favourable effect of the weaker dollar on costs and by our hedging strategy at an earnings level. PacifiCorp’s dollar turnover increased by 9% in the quarter and 5% for the six months, primarily due to higher wholesale revenues; and Infrastructure Division’s turnover increased by 16% and 12% in the quarter and half year respectively, due to higher regulated and new connections business revenues. The UK Division’s turnover increased by 51% in the quarter and 47% for the half year from a combination of increased energy balancing activities, improved retail electricity and gas sales reflecting the increased customer base and higher prices, and the acquisition of Damhead Creek CCGT power plant. PPM’s dollar turnover was higher by 50% in the quarter and 86% for the six months due to increased energy management revenues from optimisation of storage assets and sales of natural gas and added revenues from new wind facilities.

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

Cost of sales increased by £253 million to £1,038 million for the quarter and by £473 million to £2,001 million for the half year, reflecting growth in balancing our UK electricity and gas positions, increased power production and purchase costs in both UK Division and PacifiCorp and the acquisition of Damhead Creek, offset in part by the favourable US dollar translation impact. Transmission and distribution costs increased by £19 million to £147 million for the quarter and by £45 million to £296 million for the half year, 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) reduced by £9 million to £140 million for the quarter and by £9 million to £297 million for the half year. The reduction was due to the release of an environmental provision within PacifiCorp during the quarter and the favourable US dollar translation impact, offset in part by higher labour-related costs in the US to support customer growth in PacifiCorp and business growth in PPM; increased energy efficiency and customer capture costs in the UK Division as a result of customer growth; and operating costs associated with Damhead Creek. Depreciation, which is included within each of the three preceding cost categories, was in line with last year at £218 million for the half year. Increased levels of capital investment throughout the group resulted in higher depreciation charges; however, these were largely offset by the impact of the weaker dollar.

As shown in Table 1, group operating profit improved by £32 million in the quarter, and, excluding goodwill amortisation, was higher by £29 million at £282 million*. Group operating profit for the half year improved by £20 million to £472 million and, excluding goodwill amortisation, was £13 million higher at £532 million*. These results reflect a strong performance in our UK operations and good growth in PPM which, together, have more than offset PacifiCorp’s performance which has been affected by lower temperatures and plant availability. In the quarter, an environmental provision of $56 million (£31 million) was released, following the completion of a detailed environmental exposure study.

The net interest charge reduced by £22 million to £41 million for the quarter. The reduction for the half year was £34 million to £91 million, including a £10 million translation benefit from the weaker US dollar and an additional £13 million benefit to interest from the UK/US interest rate differential arising from our dollar balance sheet hedging strategy, which we have 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 mainly during the quarter.

Profit before tax, as shown in Table 1, was £212 million for the quarter and £382 million for the half year, £56 million and £55 million ahead of the quarter and half year ended 30 September 2003, respectively. Excluding goodwill amortisation, profit before tax improved by £52 million to £241 million* for the quarter and by £48 million to £442 million* for the half year, with the impact of PacifiCorp’s results being more than offset by operating profit improvements in our other businesses and the lower interest charge. A foreign exchange hedge benefit of approximately £35 million (September 2003: £14 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. We expect our earnings for the remainder of the financial year to continue to benefit from our hedging programme, with an expected hedge translation rate for the year in the range $1.50 - $1.55.

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

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, the effective rate of tax, excluding goodwill amortisation, has remained at 27%*. The tax rate 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 / %)


	Half Year
	2004/05		2003/04

Tax charge	119.3		106.2

Profit before tax	381.9		326.6
Goodwill amortisation	59.8		66.8
Profit before tax excluding goodwill*	441.7		393.4

Effective rate of tax	31.2	%	32.5	%
Effective rate of tax excluding goodwill*	27.0	%	27.0	%

Earnings per share, as shown in Table 1, improved by 2.26 pence to 7.91 pence for the quarter and by 2.29 pence to 14.20 pence for the half year. Excluding goodwill amortisation, earnings per share improved by 2.06 pence to 9.54 pence* for the quarter and by 1.91 pence to 17.47 pence* for the half year.

The dividend for the second quarter of 2004/05 will be 4.95 pence per share, an increase of 4.2% on the prior year, payable on 29 December 2004. The ADS dividend will be $0.3656 per ADS. The dividend for each of the first three quarters of 2004/05 is set at 4.95 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 half year was £791 million, of which £247 million was invested in refurbishment, upgrade and other projects. Group investment for growth totalled £544 million (69%). This included the £320 million acquisition of the 800 MW Damhead Creek CCGT power plant in Kent and associated contracts, including the benefit of a long-term gas supply agreement, our recent £72 million investment to acquire the remaining 50% of the 400 MW Brighton CCGT power plant and associated contracts, including the benefit of a long-term gas supply agreement and £43 million invested in building phase one of the 525 MW Currant Creek power plant in Utah. Net capital investment of £791 million represented fixed asset additions of £425 million, the £320 million Damhead Creek acquisition (including expenses) and the £72 million Brighton acquisition (£27 million cash consideration including expenses and 50% of net debt acquired), less £26 million of capital grants and customer contributions. We expect our net capital investment to be approximately £1.5 billion in the full year, with some 60% for growth.

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

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

Business Reviews

PacifiCorp

PacifiCorp’s turnover for the quarter to September 2004 was slightly lower than the equivalent period last year at £623 million and for the half year was £62 million lower at £1,160 million. The reduction in turnover was primarily due to the adverse impact of the weaker US dollar of £53 million for the quarter and £116 million for the half year. Dollar turnover increased by 9% for the quarter and by 5% for the half year, mainly as a result of higher wholesale revenue volume growth associated with balancing power positions (which was offset by corresponding increases in purchase costs). Retail revenues were marginally higher than the equivalent period last year, as increases from regulatory price rises and growth in customer numbers were partly offset by a reduction in the recovery of deferred power costs and lower than average customer usage due to the impact of milder weather.

PacifiCorp’s operating profit, as shown in Table 3, was £123 million for the quarter and, excluding goodwill amortisation, was £151 million*, an increase of £5 million and £2 million on the second quarter last year, respectively. For the half year, operating profit was lower by £43 million at £211 million and, excluding goodwill amortisation, was £268 million* compared to £318 million* ($430 million* compared to $490 million*) at September 2003. The £50 million reduction includes a £17 million adverse impact of the weaker US dollar net of hedging benefits from the forward sale of US dollars.

Table 3 – PacifiCorp (£m)


Quarter 2			Half Year
2004/05	2003/04		2004/05	2003/04

122.8	117.6	Operating profit	210.9	254.1
28.5	32.1	Goodwill amortisation	57.1	64.1
151.3	149.7	Operating profit excluding goodwill*	268.0	318.2

Retail revenues increased by $16 million in the half year, primarily due to rate increases of $51 million, partly offset by lower other regulatory recoveries of $13 million and, as expected, a reduction in deferred power cost recoveries of $27 million to $23 million. Customer numbers increased by 2% compared to September 2003 and this growth, together with more favourable retail pricing, contributed an additional $35 million to retail revenues. This more than offset the $30 million adverse effect on retail revenues of lower temperatures, which also contributed to an 8% reduction in average residential consumption, half year on half year. In July, PacifiCorp was named best for overall customer satisfaction in a nation-wide survey of commercial and industrial electricity customers by TQS Research, an improvement from third-place last year.

A higher level of planned and unplanned outages compared to last year reduced output at PacifiCorp’s thermal plants by 4% and impacted PacifiCorp’s results for the half year by $40 million. Other net power costs increased by $30 million as contracts expired and market prices were higher in general; this was after efficiency savings of $9 million from delivering our energy management activities more effectively. Other gross margin items improved by $2 million.

Operating efficiency initiatives delivered a further $23 million of benefits in the half year. Other net costs increased by $61 million, including higher maintenance and major plant repair expenditure and higher employee and servicing costs associated with growth in the customer

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

base. Depreciation costs increased by $5 million. The results included the release of a $56 million environmental liability provision following completion of a detailed environmental exposure study. The previous half year included $21 million of provisions and miscellaneous income that was not repeated in the current year.

PacifiCorp’s net capital investment was £203 million, with £92 million (45%) invested for organic growth. In addition to £43 million invested in Currant Creek, new connections, network reinforcement and other spend was £49 million and included our ongoing network expansion project along the Wasatch Front in Utah.

Effective from 15 September, regulators in Wyoming granted PacifiCorp $9.25 million additional revenue per year to recover increases in net wholesale purchased power costs. On 27 October, Washington state regulators granted recovery totalling $15 million for increased costs, with new rates to be implemented from 16 November. In the ongoing $111 million general rate case in Utah, regulators have approved our request to use a forward looking test period. The case is expected to be resolved by April 2005.

Separately, progress continues to be made in our Multi-State Process. In October, the regulatory commissions in Wyoming and Washington approved settlement agreements in their respective states. Settlement has also been reached with parties in Utah and Oregon, and a settlement has been reached, in principle, with parties in Idaho. Orders in these states are anticipated by the end of December.

In summary, despite a number of positive achievements, PacifiCorp had a disappointing first half with, in particular, lower temperatures and reduced plant availability affecting its profit. As a result PacifiCorp is likely to fall short of its full year profit target.

Infrastructure Division

Infrastructure Division’s turnover increased by £13 million (16%) in the quarter and £20 million (12%) for the half year to £91 million and £178 million respectively, mainly as a result of growth in our new connections business and higher external regulated revenues primarily due to increased volumes.

Infrastructure Division’s operating profit, as shown in Table 4, was higher by £3 million in the quarter, with operating profit for the half year improved by £14 million to £193 million, mainly as a result of increased regulated revenues. For the six months, regulated revenues improved by £10 million, due to favourable transmission prices and distribution sales volumes, and net costs reduced by £8 million, which more than offset higher rates and depreciation costs of £4 million.

Table 4 – Infrastructure Division (£m)


Quarter 2			Half Year
2004/05	2003/04		2004/05	2003/04

92.0	88.6	Operating profit	193.1	178.6

Infrastructure Division’s net capital investment was £126 million, with £36 million (29%) invested for organic growth, including spend on new windfarm and customer connections.

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

We continue to discuss with Ofgem all of the key issues in the lead up to the final Distribution Price Control Review (“DPCR”) proposals at the end of November. Areas of focus include seeking additional capital expenditure allowances to address specific network safety issues and for investment to improve supplies to our “worst” served customers. We are also continuing to press strongly for an allowed cost of capital figure of at least 5% post-tax, consistent with the upper end of the Ofgem range.

We are also engaged in constructive discussions with Ofgem on their proposals for the extension of the price controls for SP Transmission to run for two years from 1 April 2005. Final proposals are scheduled for the end of November 2004. Our position on cost of capital is the same as on the DPCR.

UK Division

UK Division’s turnover increased by £255 million (51%) in the quarter and £474 million (47%) for the half year to £756 million and £1,476 million, respectively, mainly from a combination of increased energy balancing activities, improved retail electricity and gas sales reflecting the increased customer base and higher prices, and the acquisition of Damhead Creek. A large proportion of turnover growth was due to increased volumes of wholesale electricity sales in England & Wales which, as part of the Division’s energy balancing activities, were offset by corresponding increases in purchase costs. The Division also experienced strong volume growth in gas and electricity turnover as a result of customer gains particularly within the domestic gas and out-of-area electricity markets. Turnover benefited to a lesser extent by increased prices in both wholesale and domestic retail activities.

The UK Division performed very strongly with operating profit, as shown in Table 5, improved by £18 million in the quarter at £22 million and, excluding goodwill amortisation, at £23 million*. For the half year, operating profit increased substantially by £40 million to £44 million and, excluding goodwill amortisation, to £47 million*. We added a further 460,000 customers in the half year bringing the total to over 4.7 million. Electricity and gas margins improved by £77 million due to continued customer growth, higher prices and the value from our integrated generation and supply operations, and a £21 million contribution from the newly acquired Damhead Creek. These gains were partly offset by increases in our energy efficiency, customer capture and service costs of £24 million. Other net costs increased by £13 million, including £8 million of Damhead Creek operating costs. The UK Division’s strong performance is expected to continue in the second half of the year.

Table 5 – UK Division (£m)


Quarter 2			Half Year
2004/05	2003/04		2004/05	2003/04

21.8	3.7	Operating profit	44.2	4.6
1.2	1.2	Goodwill amortisation	2.4	2.4
23.0	4.9	Operating profit excluding goodwill*	46.6	7.0

Since September 2003, customer numbers have risen by some 800,000 (21%) mainly within our second tier markets. A recent customer satisfaction survey by J.D. Power and Associates ranked ScottishPower as tied for first in the UK gas supplier market. Business electricity customer numbers have also risen with ScottishPower coming top for customer satisfaction in Datamonitor’s annual survey of industrial and commercial customers which polled 1,500 major energy users in the UK. Datamonitor’s report recognises our 6 Sigma transformation

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

programme and comments that we are a leader in the provision of metering. The 6 Sigma programme, which aims to improve customer handling processes, delivered further revenue and cost benefits of £2 million for the half year.

Our efficient and flexible fleet of generation plant and our rolling, forward purchasing strategy for gas and coal significantly mitigates our exposure to wholesale market price variations. We are substantially hedged over the coming winter and have significant coverage for the next 24 months. Our coverage secures average costs well below current market rates and, as a consequence, we were able to limit our recent price increases to some 9% for domestic electricity customers and 11.8% for domestic gas customers.

We are preparing our generation plant for the EU emissions scheme, due to start on 1 January 2005 and to take advantage of BETTA, the GB-wide transmission and trading regime, due to be implemented in April 2005.

Construction of approximately 100 MW of the Black Law windfarm, the largest consented onshore windfarm in the UK, is well underway and in August 2004 we received local authority approval for our Beinn Tharsuinn windfarm, with a generating capacity of approximately 30 MW. We are also working with Ocean Power Delivery and Amec to establish the feasibility of a wave power machine now under testing off Orkney.

UK Division’s net capital investment was £456 million, of which £414 million (91%) was invested for growth. The purchases of Damhead Creek and Brighton power plants bring the UK Division’s generating capacity to 6.2 GW. Other organic growth spend consisted primarily of investment in the Black Law windfarm where construction work is progressing well and we expect generation to begin in the spring of 2005.

PPM

Turnover for PPM, our competitive business in the US, increased by £28 million in the quarter and by £97 million for the half year after the adverse impact of the weaker US dollar of £6 million and £12 million, respectively. Dollar turnover improved by $61 million (50%) in the quarter and by $198 million (86%) for the half year. The growth in turnover was principally volume related and was due to increased energy management revenues from optimisation of storage assets and sales of natural gas, and added revenues from new wind facilities.

PPM’s operating profit, as shown in Table 6, rose by £6 million to £15 million for the quarter and by £9 million to £24 million (by $12 million to $36 million) for the half year. Energy management activities around our assets and long-term contracts including benefits from transmission and contract delivery flexibility, decisions on how plants are operated and the selling or storing of displaced gas, contributed an additional $12 million. Renewable energy profit improved by $9 million, primarily due to last year’s investment in new windfarms delivering substantial volume growth. Gas storage profits were in line with the six month period last year, when we had a very favourable gas storage performance and we expect continued strong performance during the second half of the year. Net operating costs required to support increased business activities and infrastructure were higher by $9 million.

Table 6 – PPM (£m)


Quarter 2			Half Year
2004/05	2003/04		2004/05	2003/04
15.3	9.7	Operating profit	23.6	14.8
0.1	0.2	Goodwill amortisation	0.3	0.3
15.4	9.9	Operating profit excluding goodwill*	23.9	15.1

PPM’s net capital investment was £6 million, with £2 million (33%) invested for growth, including preliminary investment in the Waha gas storage facility in West Texas. PPM’s wind development activities continue to focus on the pipeline of wind generation projects and, following renewal of the US federal Production Tax Credit in October, PPM announced plans to add 175 MW of new wind power. Both fully permitted, the 75 MW Klondike II project in Oregon and the 100 MW Trimont project in Minnesota are expected to be earnings enhancing once completed in autumn 2005. The capital invested in these two projects is expected to be approximately $200 million. PPM has signed a 15-year power purchase agreement with Great River Energy for all the output of the Trimont windfarm and negotiations are ongoing to finalise the long-term power sales agreement from Klondike II.

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 £84 million from £4,752 million to £4,836 million in the six 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. The increase in debt is discussed in Section 3 “Liquidity and Capital Resources”.

3. Liquidity and Capital Resources

For the six months to September 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.

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

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 30 September 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 95% 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 six months to September 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 half year by £257 million to £433 million, mainly due to the lower operating profit in PacifiCorp, provision movements, an increase in working capital requirements in PPM (which will benefit performance later in the year) and higher coal stocks in UK Division. Interest, tax and dividend payments totalled £227 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, fixed asset investments, and acquisitions and disposals, other than the £320 million Damhead Creek acquisition, were £16 million. Financing net inflows, other than changes in net debt, were £83 million mainly as a result of a £95 million cash receipt arising on the maturing of net investment hedging derivatives. These cash flows combined provided cash of £305 million, which contributed to the group’s net capital investment cash spend of £714 million. After non-cash movements of £162 million relating to the adverse effect of foreign exchange and the acquisition of debt following the purchase of the remaining 50% of Brighton power plant, net debt at 30 September 2004 was £4,296 million, £571 million higher than at 31 March 2004. Gearing (net debt/equity shareholders’ funds) was 90%, compared to 79% as at 31 March 2004.

Included in net debt are short-term bank and other deposits of £977 million, down £370 million from March 2004 principally as a result of the £320 million acquisition of Damhead Creek. Cash generated from operations of £433 million and the £95 million proceeds from the maturity of net investment hedge derivatives largely funded our organic capital expenditure and financial investment of £379 million and dividend payments of £204 million. Total debt balances increased from £5,072 million at March 2004 to £5,273 million at September 2004 as a result of £116 million of debt acquired following the purchase of the remaining 50% of Brighton power plant, translation impact and other non-cash changes of £49 million and a net £36 million drawdown of borrowings and overdrafts.

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 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 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 six month period to September 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 does not account for commodity volume risk. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed 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

As at 30 September 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 £5.5 million, as measured by the VaR computations, compared to £9.7 million as at 30 September 2003. The average daily VaR (five-day holding) for the six months to 30 September 2004 was £7.2 million. The maximum and minimum VaR measured during the six months to 30 September 2004 were £12.7 million and £4.2 million, respectively.

PacifiCorp

At 30 September 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 £9.0 million, as measured by the VaR computations, compared to £8.2 million at 30 September 2003. The average daily VaR (five-day holding) for the six months to 30 September 2004 was £10.1 million. The maximum and minimum VaR measured during the six months to 30 September 2004 were £13.8 million and £7.0 million, respectively.

PPM

At 30 September 2004, PPM’s estimated potential five-day unfavourable impact on fair value of the energy commodity portfolio (VaR) over the next 24 months was £5.6 million, as measured by the VaR computations, compared to £3.0 million at 30 September 2003. The average daily VaR (five-day holding) for the six months to 30 September 2004 was £4.0 million. The maximum and minimum VaR measured during the six months to 30 September 2004 were £6.9 million and £1.2 million, respectively.

Insurance Risk Management

In the past six 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 six months to September 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 a cash receipt 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 six months ended 30 September 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 six months ended 30 September 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.

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;

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 30 September				Six months ended 30 September
	Notes	2004 £m		2003 £m		2004 £m		2003 £m
Turnover: group and share of joint ventures and associates		1,581.8		1,287.7		3,074.6		2,540.4
Less: share of turnover in joint ventures		(8.8	)	(7.8	)	(20.0	)	(14.9	)
Less: share of turnover in associates		(0.2	)	(0.1	)	(0.5	)	(0.3	)

Group turnover	2	1,572.8		1,279.8		3,054.1		2,525.2
Cost of sales		(1,038.3	)	(785.8	)	(2,000.7	)	(1,527.5	)

Gross profit		534.5		494.0		1,053.4		997.7
Transmission and distribution costs		(147.1	)	(128.5	)	(296.0	)	(251.3	)
Administrative expenses (including goodwill amortisation)		(140.3	)	(149.1	)	(296.6	)	(305.9	)
Other operating income		4.8		3.2		11.0		11.6

Operating profit	2	251.9		219.6		471.8		452.1
Share of operating profit/(loss) in joint ventures		0.7		(0.4	)	0.9		(0.5	)
Share of operating (loss)/profit in associates		(0.1	)	—		0.1		0.1

Profit on ordinary activities before interest		252.5		219.2		472.8		451.7
Net interest and similar charges
—Group		(39.3	)	(62.0	)	(87.5	)	(122.5	)
—Joint ventures		(1.7	)	(1.3	)	(3.4	)	(2.6	)

		(41.0	)	(63.3	)	(90.9	)	(125.1	)

Profit on ordinary activities before taxation		211.5		155.9		381.9		326.6
Taxation	3	(65.2	)	(51.1	)	(119.3	)	(106.2	)

Profit after taxation		146.3		104.8		262.6		220.4
Minority interests (including non-equity)		(1.6	)	(1.6	)	(2.6	)	(2.6	)

Profit for the period		144.7		103.2		260.0		217.8
Dividends	5	(91.0	)	(87.4	)	(182.1	)	(174.9	)

Profit retained		53.7		15.8		77.9		42.9

Earnings per ordinary share	4	7.91	p	5.65	p	14.20	p	11.91	p

Diluted earnings per ordinary share	4	7.67	p	5.58	p	13.82	p	11.83	p

Dividends per ordinary share	5	4.95	p	4.75	p	9.90	p	9.50	p

The above results relate to continuing operations.

The Notes on pages x to x form part of these Accounts.

Statement of Total Recognised Gains and Losses

for the six months ended 30 September 2004


	Unaudited
	Six months ended 30 September
	2004 £m		2003 £m
Profit for the period	260.0		217.8
Exchange movement on translation of overseas results and net assets	56.9		(177.3	)
Translation differences on foreign currency hedging	(55.8	)	152.9
Tax on translation differences on foreign currency hedging	4.0		—
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	271.4		193.4

Reconciliation of Movements in Shareholders’ Funds

for the six months ended 30 September 2004


	Unaudited
	Six months ended 30 September
	2004 £m		2003 (As restated – Note 1) £m
Profit for the period	260.0		217.8
Dividends	(182.1	)	(174.9	)

Profit retained	77.9		42.9
Exchange movement on translation of overseas results and net assets	56.9		(177.3	)
Translation differences on foreign currency hedging	(55.8	)	152.9
Tax on translation differences on foreign currency hedging	4.0		—
Revaluation reserve arising on the purchase of the remaining 50% of the Brighton Power Station	6.3		—
Share capital issued	14.6		5.4
Consideration paid in respect of purchase of own shares held under trust	(28.5	)	(27.5	)
Credit in respect of employee share awards	4.9		3.6
Consideration received in respect of sale of own shares held under trust	6.1		0.2

Net movement in shareholders’ funds	86.4		0.2
Opening shareholders’ funds (as restated for implementation of UITF 38 ‘Accounting for ESOP Trusts’)	4,690.9		4,554.9

Closing shareholders’ funds	4,777.3		4,555.1

The Notes on pages x to x form part of these Accounts.

Group Cash Flow Statement

for the six months ended 30 September 2004


		Unaudited
		Six months ended 30 September
	Notes	2004 £m		2003 (As restated – Note 1) £m
Cash inflow from operating activities	6	433.3		690.4
Dividends received from joint ventures		1.6		0.2
Returns on investments and servicing of finance		(26.5	)	(128.5	)
Taxation		1.4		(96.8	)
Capital expenditure and financial investment		(378.6	)	(360.4	)

Cash flow before acquisitions and disposals		31.2		104.9
Acquisitions and disposals		(319.6	)	(3.5	)
Equity dividends paid		(204.0	)	(219.7	)

Cash outflow before use of liquid resources and financing		(492.4	)	(118.3	)
Management of liquid resources	7	(71.8	)	(40.8	)
Financing
—Issue of ordinary share capital		14.6		5.4
—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		(22.4	)	(27.3	)
—Increase in debt	7	15.8		421.5

		99.3		471.1

(Decrease)/increase in cash in period	7	(464.9	)	312.0

Reconciliation of Net Cash Flow to Movement in Net Debt

for the six months ended 30 September 2004


		Unaudited
		Six months ended 30 September
	Note	2004 £m		2003 £m
(Decrease)/increase in cash in period		(464.9	)	312.0
Cash inflow from increase in debt		(15.8	)	(421.5	)
Cash outflow from movement in liquid resources		71.8		40.8

Change in net debt resulting from cash flows		(408.9	)	(68.7	)
Net debt acquired		(116.1	)	—
Foreign exchange movement		(37.9	)	115.6
Other non-cash movements		(8.2	)	(5.9	)

Movement in net debt in period		(571.1	)	41.0
Net debt at end of previous period		(3,724.5	)	(4,321.0	)

Net debt at end of period	7	(4,295.6	)	(4,280.0	)

The Notes on pages x to x form part of these Accounts.

Group Balance Sheet

as at 30 September 2004


		Unaudited
	Notes	30 September 2004 £m		30 September 2003 (As restated – Note 1) £m		31 March 2004 £m
Fixed assets
Intangible assets		1,932.6		2,109.9		1,855.9
Tangible assets		9,476.1		8,984.9		8,756.6
Investments
—Investments in joint ventures:
Share of gross assets		72.2		108.4		180.8
Share of gross liabilities		(50.8	)	(108.3	)	(157.3	)

		21.4		0.1		23.5
—Loans to joint ventures		12.5		38.2		38.8

		33.9		38.3		62.3
—Investments in associates		2.3		2.8		2.7
—Other investments		123.0		145.2		129.8

		159.2		186.3		194.8

		11,567.9		11,281.1		10,807.3

Current assets
Stocks	8	322.5		225.5		185.5
Debtors
—Gross debtors		1,401.7		1,528.5		1,576.2
—Less non-recourse financing		(108.7	)	(139.8	)	(109.5	)

		1,293.0		1,388.7		1,466.7
Short-term bank and other deposits		977.1		1,007.4		1,347.3

		2,592.6		2,621.6		2,999.5

Creditors: amounts falling due within one year
Loans and other borrowings		(443.6	)	(304.4	)	(410.7	)
Other creditors		(1,632.4	)	(1,542.4	)	(1,658.7	)

		(2,076.0	)	(1,846.8	)	(2,069.4	)

Net current assets		516.6		774.8		930.1

Total assets less current liabilities		12,084.5		12,055.9		11,737.4
Creditors: amounts falling due after more than one year
Loans and other borrowings (including convertible bonds)		(4,829.1	)	(4,983.0	)	(4,661.1	)
Provisions for liabilities and charges
—Deferred tax		(1,313.8	)	(1,292.7	)	(1,242.2	)
—Other provisions		(510.0	)	(585.3	)	(504.5	)

		(1,823.8	)	(1,878.0	)	(1,746.7	)
Deferred income		(595.8	)	(573.6	)	(577.8	)

Net assets	2	4,835.8		4,621.3		4,751.8

Called up share capital	9	931.7		928.7		929.8
Share premium	9	2,288.4		2,269.1		2,275.7
Revaluation reserve	9	47.0		42.6		41.6
Capital redemption reserve	9	18.3		18.3		18.3
Merger reserve	9	406.4		406.4		406.4
Profit and loss account	9	1,085.5		890.0		1,019.1

Equity shareholders’ funds	9	4,777.3		4,555.1		4,690.9
Minority interests (including non-equity)		58.5		66.2		60.9

Capital employed		4,835.8		4,621.3		4,751.8

The Notes on pages x to x form part of these Accounts.

Approved by the Board on 10 November 2004 and signed on its behalf by



/s/ Charles Miller Smith				/s/ David Nish
Charles Miller Smith				David Nish
Chairman				Finance Director

Notes to the Interim Accounts (Unaudited)

for the six months ended 30 September 2004

1 Basis of preparation

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

(b) The interim Accounts are unaudited but have been formally reviewed by the auditors. 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 six month period to 30 September 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 30 September 2003
	Fixed asset investments		Other creditors		Other provisions		Net assets
	£m		£m		£m		£m
As previously reported	310.7		1,553.0		592.0		4,728.4
Effect of implementing new accounting policy	(124.4	)	(10.6	)	(6.7	)	(107.1	)

As restated	186.3		1,542.4		585.3		4,621.3

(d) The relevant exchange rates applied in the preparation of these interim Accounts are detailed in Note 13.

2 Segmental information

(a) Turnover by segment

Three months ended 30 September

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)

763.1

509.6

(7.2

)

(8.4

)

755.9

501.2

Infrastructure Division – Power Systems

171.1

156.2

(80.0

)

(77.9

)

91.1

78.3

United Kingdom total

847.0

579.5

United States

PacifiCorp

623.7

625.8

(0.4

)

(0.5

)

623.3

625.3

PPM

104.9

77.7

(2.4

)

(2.7

)

102.5

75.0

United States total

725.8

700.3

Total

(ii)

1,572.8

1,279.8

Six months ended 30 September

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)

1,490.2

1,018.4

(13.9

)

(16.3

)

1,476.3

1,002.1

Infrastructure Division – Power Systems

340.0

316.9

(162.1

)

(158.6

)

177.9

158.3

United Kingdom total

1,654.2

1,160.4

United States

PacifiCorp

1,161.1

1,222.9

(1.6

)

(1.1

)

1,159.5

1,221.8

PPM

245.2

148.3

(4.8

)

(5.3

)

240.4

143.0

United States total

1,399.9

1,364.8

Total

(ii)

3,054.1

2,525.2

2 Segmental information continued

(b) Operating profit by segment


			Three months ended 30 September
	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)		23.0	(1.2	)	21.8	4.9	(1.2	)	3.7
Infrastructure Division – Power Systems			92.0	—		92.0	88.6	—		88.6

United Kingdom total			115.0	(1.2	)	113.8	93.5	(1.2	)	92.3

United States
PacifiCorp	(iii	)	151.3	(28.5	)	122.8	149.7	(32.1	)	117.6
PPM			15.4	(0.1	)	15.3	9.9	(0.2	)	9.7

United States total			166.7	(28.6	)	138.1	159.6	(32.3	)	127.3

Total			281.7	(29.8	)	251.9	253.1	(33.5	)	219.6


			Six months ended 30 September
	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)		46.6	(2.4	)	44.2	7.0	(2.4	)	4.6
Infrastructure Division – Power Systems			193.1	—		193.1	178.6	—		178.6

United Kingdom total			239.7	(2.4	)	237.3	185.6	(2.4	)	183.2

United States
PacifiCorp	(iii	)	268.0	(57.1	)	210.9	318.2	(64.1	)	254.1
PPM			23.9	(0.3	)	23.6	15.1	(0.3	)	14.8

United States total			291.9	(57.4	)	234.5	333.3	(64.4	)	268.9

Total			531.6	(59.8	)	471.8	518.9	(66.8	)	452.1

(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 £46.1 million and £59.8 million and operating profit of £9.3 million and £12.5 million for the three months and six months to September 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 three months and six months to September 2004 included the release of a £31 million ($56 million) environmental liability provision following completion of a detailed environmental exposure study.

(c) Net assets by segment


	Note	30 Sept 2004 £m		30 Sept 2003 (As restated – Note 1) £m		31 March 2004 £m
United Kingdom
UK Division – Integrated Generation and Supply		1,500.7		845.7		1,022.5
Infrastructure Division – Power Systems		2,413.3		2,248.5		2,337.4

United Kingdom total		3,914.0		3,094.2		3,359.9

United States
PacifiCorp		6,142.7		6,539.2		5,935.8
PPM		628.4		423.5		439.0

United States total		6,771.1		6,962.7		6,374.8

Total		10,685.1		10,056.9		9,734.7

Unallocated net liabilities	(i)	(5,849.3	)	(5,435.6	)	(4,982.9	)

Total		4,835.8		4,621.3		4,751.8

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

Notes to the Interim Accounts (Unaudited) continued

for the six months ended 30 September 2004

3 Taxation

The charge for taxation, including deferred tax, for the six month period ended 30 September 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 £18.3 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 and net asset value 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 30 September		Six months ended 30 September
	2004	2003	2004	2003
Basic earnings per share
Profit for the period (£ million)	144.7	103.2	260.0	217.8
Weighted average share capital (number of shares, million)	1,829.1	1,828.5	1,830.5	1,829.5

Diluted earnings per share
Profit for the period (£ million)	147.8	104.7	266.0	219.3
Weighted average share capital (number of shares, million)	1,926.6	1,874.0	1,925.2	1,854.4

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 second interim dividend of 4.95 pence per ordinary share is payable on 29 December 2004 to shareholders on the register at 19 November 2004. This dividend, together with the first interim dividend for the quarter ended 30 June 2004 of 4.95 pence per ordinary share, represents total dividends of 9.90 pence per ordinary share for the first half of the financial year. In the previous year, a second interim dividend of 4.75 pence was declared for the quarter ended 30 September 2003, representing total dividends of 9.50 pence per ordinary share for the first half of the financial year.

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


	Six months ended 30 September
	2004 £m		2003 (As restated – Note 1) £m
Operating profit	471.8		452.1
Depreciation and amortisation	281.3		286.0
Profit on sale of tangible fixed assets	(1.5	)	(5.2	)
Amortisation of share scheme costs	4.9		3.6
Release of deferred income	(9.9	)	(10.0	)
Movements in provisions for liabilities and charges	(93.3	)	(34.5	)
Increase in stocks	(130.4	)	(76.5	)
Decrease in debtors	25.6		200.8
Decrease in creditors	(115.2	)	(125.9	)

Net cash inflow from operating activities	433.3		690.4

7 Analysis of net debt


	At 1 April 2004 £m		Cash flow £m		Acquisitions (excl. cash & overdrafts) £m		Exchange £m		Other non-cash changes £m		At 30 Sept 2004 £m
Cash at bank	758.9		(444.7	)	—		2.7		—		316.9
Overdrafts	(20.1	)	(20.2	)	—		(0.4	)	—		(40.7	)

			(464.9	)

Debt due after 1 year	(4,646.1	)	(216.2	)	(116.1	)	(38.0	)	202.5		(4,813.9	)
Debt due within 1 year	(390.6	)	200.4		—		(2.0	)	(210.7	)	(402.9	)
Finance leases	(15.0	)	—		—		(0.2	)	—		(15.2	)

			(15.8	)
Other deposits	588.4		71.8		—		—		—		660.2

Total	(3,724.5	)	(408.9	)	(116.1	)	(37.9	)	(8.2	)	(4,295.6	)

‘Other non-cash changes’ to net debt represents the movement in debt of £210.7 million due after one year to due within one year, amortisation of finance costs of £4.5 million and finance costs of £3.7 million representing the effects of the RPI on bonds carrying an RPI coupon.

8 Stocks


	At 30 September		At 31 March 2004 £m
	2004 £m	2003 £m	At 31 March 2004 £m
Raw materials and consumables	122.5	139.5	91.7
Fuel stocks	194.6	73.8	88.2
Work in progress	5.4	12.2	5.6

	322.5	225.5	185.5

9 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	—	—	—	—		—	—	77.9		77.9
Share capital issued
– ESOP	1,401	0.7	4.8	—		—	—	—		5.5
– PacifiCorp Stock Incentive Plan	2,578	1.2	7.9	—		—	—	—		9.1
Consideration paid in respect of purchase of own shares held under trust	—	—	—	—		—	—	(28.5	)	(28.5	)
Credit in respect of employee share awards	—	—	—	—		—	—	4.9		4.9
Consideration received in respect of sale of own shares held under trust	—	—	—	—		—	—	6.1		6.1
Revaluation reserve arising on the purchase of the remaining 50% of the Brighton Power Station	—	—	—	6.3		—	—	—		6.3
Revaluation surplus realised	—	—	—	(0.9	)	—	—	0.9		—
Exchange movement on translation of overseas results and net assets	—	—	—	—		—	—	56.9		56.9
Translation differences on foreign currency hedging	—	—	—	—		—	—	(55.8	)	(55.8	)
Tax on translation differences on foreign currency hedging	—	—	—	—		—	—	4.0		4.0

Balance at 30 September 2004	1,863,518	931.7	2,288.4	47.0		18.3	406.4	1,085.5		4,777.3

10 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.


	Six months ended 30 September
	2004 £m		2003 £m
(a) Reconciliation of profit for the financial period to US GAAP:
Profit for the financial period under UK GAAP	260.0		217.8
US GAAP adjustments:
Amortisation of goodwill	59.8		66.8
US regulatory net assets	(21.8	)	(45.3	)
Pensions	4.9		4.3
Depreciation on revaluation uplift	0.9		0.9
Decommissioning and mine reclamation	(35.8	)	(4.9	)
PacifiCorp Transition Plan costs	(4.2	)	(22.7	)
FAS 133	(30.7	)	67.1
Other	(4.7	)	(0.2	)

	228.4		283.8
Deferred tax effect of US GAAP adjustments	27.4		21.6

Profit for the period under US GAAP before cumulative adjustment for FAS 143	255.8		305.4
Cumulative adjustment for FAS 143	—		(0.6	)

Profit for the period under US GAAP	255.8		304.8
Earnings per share under US GAAP	13.97	p	16.66	p
Diluted earnings per share under US GAAP	13.94	p	16.52	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 six months ended 30 September 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.

Notes to the Interim Accounts (Unaudited) continued

for the six months ended 30 September 2004

10 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:


	30 Sept 2004 £m		30 Sept 2003 (As restated – Note 1) £m		31 March 2004 £m
Equity shareholders’ funds under UK GAAP	4,777.3		4,555.1		4,690.9
US GAAP adjustments:
Goodwill	572.3		572.3		572.3
Business combinations	(199.0	)	(215.9	)	(196.1	)
Amortisation of goodwill	213.3		109.5		150.0
US regulatory net assets	653.7		967.9		724.7
Pensions	(16.0	)	(400.5	)	(18.9	)
Dividends	91.0		87.4		112.9
Revaluation	(60.3	)	(54.0	)	(54.0	)
Depreciation on revaluation uplift	13.3		11.4		12.4
Decommissioning and mine reclamation	(52.6	)	(7.2	)	(14.9	)
PacifiCorp Transition Plan costs	18.4		31.3		22.2
FAS 133	29.1		(57.4	)	2.2
ESOP shares held in trust	—		77.0		—
Other	13.9		(7.1	)	(12.9	)
Deferred tax:
Effect of US GAAP adjustments	(259.5	)	(135.1	)	(275.0	)
Effect of differences in methodology	13.9		(23.3	)	14.5

Equity shareholders’ funds under US GAAP	5,808.8		5,511.4		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 30 September 2004 of £29.1 million includes a net liability of £178.9 million which is subject to regulation and is therefore offset by a US regulatory asset of £178.9 million included within ‘US regulatory net assets’ above.

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:


	Six months ended 30 September
	2004		2003
Profit for the financial period under US GAAP (£ million)	255.8		304.8
Reversal of APB 25 stock compensation expense (included within the ‘Other’ adjustment) (£ million)	1.0		1.4
Stock compensation expense calculated under FAS 123 (£ million)	(2.4	)	(2.3	)
Pro forma profit for the financial period under US GAAP (£ million)	254.4		303.9
Basic earnings per share under US GAAP	13.97	p	16.66	p
Pro forma basic earnings per share under US GAAP	13.90	p	16.61	p
Diluted earnings per share under US GAAP	13.94	p	16.52	p
Pro forma diluted earnings per share under US GAAP	13.87	p	16.47	p

Pensions and other post-retirement benefits

The components of the pension and other post-retirement benefit costs for the periods ended 30 September 2004 and 2003 were as follows:


	Pension costs Six months ended 30 September				Other post- retirement benefit costs Six months ended 30 September
	2004 £m		2003 £m		2004 £m		2003 £m
Service cost	26.3		22.7		2.4		2.3
Interest cost	82.0		78.9		8.6		10.6
Expected return on plans’ assets	(90.4	)	(83.9	)	(7.3	)	(8.2	)
Amortisation of experience losses	10.7		13.2		1.7		2.1
Amortisation of prior service cost	(0.1	)	(0.4	)	—		—

Net periodic benefit cost	28.5		30.5		5.4		6.8

10 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 30 September 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 20 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. PacifiCorp expects future costs relating to these matters may be significant and consist primarily of additional environmental requirements. The group has accumulated approximately £11.2 million in costs at 30 September 2004 for ongoing hydroelectric relicensing and it is expected that these and other future costs will be included in rates, and as such, will not have a material adverse impact on the group’s results and financial position under US GAAP.

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.

11 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.

Notes to the Interim Accounts (Unaudited) continued

for the six months ended 30 September 2004

12 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.

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.

13 Exchange rates

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


	Six months ended 30 September
	2004			2003
Average rate for quarters ended
30 June	$	1.81	/£	$	1.62	/£
30 September	$	1.82	/£	$	1.61	/£

Closing rate as at 30 September	$	1.81	/£	$	1.66	/£

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