SECURITIES AND EXCHANGE COMMISSIONS
WASHINGTON, DC 20549
FORM 6-K
REPORT OF FOREIGN PRIVATE ISSUER
PURSUANT TO RULE 13a-16 OR 15a-16 OF
THE SECURITIES EXCHANGE ACT OF 1934
For the month of June 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. Annual Report for the year ended March 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 | June 10, 2004 |
By: | /s/ Donald McPherson | |||||
| Donald McPherson Assistant Secretary | ||||||||
| Annual Report and Accounts 2003/04 |
Financial Highlights
| 2004 |
2003 |
2004* |
2003* |
|||||||||||||
| Turnover |
£ | 5,797 | m | £ | 5,274 | m | $ | 10,666 | m | $ | 8,333 | m | ||||
| Operating profit |
£ | 1,023 | m | £ | 946 | m | $ | 1,882 | m | $ | 1,494 | m | ||||
| Operating profit excluding goodwill |
£ | 1,151 | m | £ | 1,085 | m | $ | 2,118 | m | $ | 1,714 | m | ||||
| Profit before tax |
£ | 792 | m | £ | 697 | m | $ | 1,457 | m | $ | 1,101 | m | ||||
| Profit before tax excluding goodwill |
£ | 920 | m | £ | 836 | m | $ | 1,693 | m | $ | 1,321 | m | ||||
| Earnings per ordinary share/per ADS |
29.40 | p | 26.17 | p | $ | 2.17 | $ | 1.66 | ||||||||
| Earnings per ordinary share/per ADS excluding goodwill |
36.40 | p | 33.71 | p | $ | 2.69 | $ | 2.13 | ||||||||
| Dividends per ordinary share/per ADS |
20.50 | p | 28.71 | p | $ | 1.42 | $ | 1.83 | ||||||||
| * | Amounts for the financial years ended 31 March 2004 and 31 March 2003 have been translated, solely for the convenience of the reader, at the closing exchange rates on 31 March of $1.84 to £1.00 and $1.58 to £1.00 respectively. Dividends per American Depositary Share (“ADS”) are shown based on the actual amounts in US dollars. One ADS represents four ordinary shares. |
ScottishPower is an international energy company listed on both the London and New York Stock Exchanges.
Through its operating subsidiaries the company provides in excess of 5.8 million electricity or gas services to homes and businesses in the western US and across the UK.
This Annual Report and Accounts examines our performance in 2003/04 and assesses the issues and opportunities ahead.
Contents
| Report of the Directors | ||
| 3 |
Chairman’s Statement | |
| 5 |
Chief Executive’s Review | |
| 9 |
Business Review | |
| 34 |
Financial Review | |
| 62 |
Board of Directors and Executive Team | |
| 65 |
Corporate Governance | |
| 72 |
Remuneration Report of the Directors | |
| 84 |
Safe Harbor Statement | |
| Accounts 2003/04 | ||
| 85 |
Accounting Policies and Definitions | |
| 90 |
Group Profit and Loss Account | |
| 92 |
Statement of Total Recognised Gains and Losses | |
| 93 |
Group Cash Flow Statement | |
| 94 |
Group Balance Sheet | |
| 95 |
Notes to the Group Accounts | |
| 144 |
Company Balance Sheet | |
| 145 |
Notes to the Company Balance Sheet | |
| 146 |
Principal Subsidiary Undertakings and Other Investments | |
| 147 |
Independent Auditors’ Report | |
| 148 |
Five Year Summary | |
| 149 |
Glossary of Financial Terms and US Equivalents | |
| Investor Information | ||
| 150 |
Investor Information | |
| 157 |
Financial Calendar | |
| 158 |
Shareholder Services | |
| 159 |
Index | |
| 160 |
Glossary of Terms | |
ScottishPower Annual Report and Accounts 2003/04 1
ScottishPower has benefited from its clear focus on energy and the more settled conditions that have returned to its markets.
Charles Miller Smith, Chairman
2 ScottishPower Annual Report and Accounts 2003/04
Getting better
ScottishPower has benefited from its clear focus on energy and the more settled conditions that have returned to its markets. We have got better at supplying customers with power and have improved performance by sharpening up our processes for providing energy and investing in organic growth projects to build long-term value. Our businesses continued to make good progress and delivered their planned targets for 2003/04.
The group’s earnings per share* for the year were 36.4 pence, an improvement of 8% for the 12 months. Profits, earnings and investment increased; debt and interest charges fell, and the statistics on customer service, network reliability, and energy and risk management are all positive. The fourth quarter dividend of 6.25 pence per share brings the total dividends for the year to 31 March 2004 to 20.5 pence compared to 28.7 pence last year. Our goal now is to increase dividends broadly in line with earnings.
Business Progress
Our US businesses made further strides in operating efficiency and customer service standards. PacifiCorp benefited from strong economic trends in its service territories, with increases in customer numbers and load growth, while simultaneously reducing costs. We invested in network expansion and generating plant capacity and in the year we have been awarded $100 million in additional annual revenue from US rate cases. PPM, our newest business, invested substantially in additional wind generation and gas storage capacity.
Our UK businesses also did well. The Infrastructure Division lifted operating profit by 7% thanks to continued emphasis on reducing costs and enhancing service. The investment in modernising our distribution networks and replacing equipment has placed our operations in a strong position ahead of next year’s price review. The UK Division gained 600,000 new customers, wholesale energy prices recovered from last year’s historic low and operating profit* rose 30%. Customer numbers passed four million for the first time and we have added to both our conventional and renewable power plant portfolio.
Safety Matters
We are deeply saddened to report the death of Alan Ronald, a transmission linesman who died doing his job on 16 December 2003. ScottishPower has an improving record on safety and it is given top priority by our Board and all our operations. We are committed to minimising the dangers of our installations and know we need to do more to remind staff, customers and the public that we all bear responsibility for safe practices. ScottishPower will publish a full report on its social and environmental impact later in the year.
Board Appointments
There have been several changes to the Board this year. Simon Lowth joined the Board as Director, Corporate Strategy and Development, in September 2003. Judi Johansen, President and Chief Executive of PacifiCorp, was appointed in October 2003.
Mair Barnes and Sir Peter Gregson will retire at the AGM after completing two terms of office each. We thank them for their support and wise counsel and wish them well.
In their places we welcome Vicky Bailey, formerly an Assistant Secretary for Policy and International Affairs at the US Department of Energy, an ex-member of the Federal Energy Regulatory Commission who has also served as an Indiana state regulator, and Nancy Wilgenbusch, a distinguished community administrator and President of the Marylhurst University in Portland, Oregon. Their experiences of US business, government, academic and community management strengthen the close regulatory and community relations we are forging.
Staff
On behalf of shareholders and the Board, I want to acknowledge the dedication of our staff whose hard work has achieved this performance and thank them for their efforts.
Outlook
ScottishPower believes that the next 12 months offers promising opportunities. We expect that our strategy of investing for organic growth and improving operational performance will deliver value for our shareholders.
| /s/ Charles Miller Smith |
| Charles Miller Smith, Chairman 25 May 2004 |
| * | Excluding goodwill amortisation |
ScottishPower Annual Report and Accounts 2003/04 3
Dear Shareholder,
This has been another good year for ScottishPower. Our skills in serving customers, balancing demand and supply, and managing our assets, together with our increased investment programme, have resulted in higher growth, more efficient performance and better returns.
Ian Russell, Chief Executive
4 ScottishPower Annual Report and Accounts 2003/04
| 1 | Delivering the Strategy | |||
| 2 | Investing for Organic Growth | |||
| 3 | Improving Operational Performance | |||
| 4 | Health and Safety | |||
| 5 | Corporate Social Responsibility | |||
| 6 | Employees | |||
| 7 | Conclusion |
This has been another good year for ScottishPower. Our skills in serving customers, balancing demand and supply, and managing our assets, together with our increased investment programme, have resulted in higher growth, more efficient performance and better returns. All of our businesses delivered improved performance, principally due to increased revenues with higher volumes and prices, and the returns from investing in generation, networks and gas storage. As a result, pre-tax profit* increased by £84 million to £920 million, and earnings per share* increased by 8% to 36.4 pence.
The full year dividend of 20.50 pence per share is covered 1.78 times by earnings per share* in line with our stated policy effective from 1 April 2003. The dividend for each of the first three quarters of 2004/05 will be 4.95 pence per share, with the balance of the total dividend to be set in the fourth quarter. We remain committed to our stated policy of growing dividends broadly in line with earnings.
We remain focused on delivering our established strategy of improving operational performance and achieving organic growth by investing in projects with a range of attractive returns.
In improving our operational performance, we aim to increase revenue through regulatory rate cases and customer growth which, together with driving down costs across the group, bring improvements to the bottom line. In the year we have been awarded $100 million in additional annual revenue from US rate cases; grown our UK customer base by 600,000 to 4.25 million (16% growth); and reduced costs across the group by £49 million. We have also increased network reliability, with PacifiCorp reducing the average outage time for customers by 16% and Infrastructure Division reducing network faults by 8.5%.
We spent approximately £900 million in the year on net capital investment, some 40% of which was in projects which will deliver organic growth. We have exercised strict capital discipline and all our capital projects meet rigorous criteria for value creation. We have also developed a high quality pipeline of projects that offer a range of attractive returns. We believe current allowed regulatory returns justify investment in our regulated assets and, through incentives, we believe that we can better these returns. In our competitive businesses we seek returns of at least 2% above our weighted average cost of capital. All new investments, assessed on a risk adjusted returns basis, are expected to be earnings enhancing and support our aim of retaining our A– credit rating for our principal operating subsidiaries. In the year, we invested in windfarm projects in the US and UK totalling more than 534 MW; commenced initial work on the new 525 MW Currant Creek gas-fired power plant in Utah; undertook substantial network investment in the US of 564 MVA; and added to our gas storage capacity. We currently forecast investing approximately £1.2 billion in the year to March 2005 in networks, generation and gas storage, all of which will deliver a range of attractive returns, some 50% of which is expected to deliver organic growth.
2 Investing for Organic Growth
Net investment in assets totalled £901 million in the year, with £247 million invested in the final quarter. Our organic growth expenditure totalled £364 million for the year, with 58% of that figure invested in our regulated businesses and 42% in our competitive businesses. Geographically, £268 million (74%) of growth spend was invested in the US and £96 million (26%) in the UK.
PacifiCorp’s net investment in assets totalled £419 million, with £151 million (36%) of this invested for organic growth. Of this, £126 million was invested in new transmission and system networks, including new connections and system reinforcement spend and in our major network expansion project along the Wasatch Front in Utah. New generation growth investment of £25 million included spend on Currant Creek, the 525 MW plant, in Utah. In May 2004, PacifiCorp announced it had selected Summit Vineyard LLC to construct a 534 MW gas-fired plant for approximately $330 million. The proposed new plant, named Lake Side, would be located near Salt Lake City, Utah, and would provide base load power starting in 2007.
In our Infrastructure Division, net investment in assets was £260 million, with £60 million (23%) in organic growth areas such as new customer connections and network upgrading, including ongoing reinforcement projects in Dumfries & Galloway and Wrexham. Compared to 2002/03, we have increased investment in the replacement of network assets. The total number of distribution network faults has reduced by
| * | Excluding goodwill amortisation |
ScottishPower Annual Report and Accounts 2003/04 5
Chief Executive’s Review
8.5% in the year and we have achieved reductions in the unit cost of faults on our 33kV cable network and 11kV overhead line network.
In our UK Division, net investment in assets was £93 million, with £36 million (39%) of this invested in organic growth projects. This included investment in new wind generation of £26 million, with Cruach Mhor (30 MW) windfarm now fully commissioned and Black Law (96 MW) under construction, following receipt of planning consent in February 2004. The project to upgrade and increase the capacity of the Cruachan pumped storage hydro station from 400 MW to 440 MW is near completion. Offshore windfarm activity is also progressing with the allocation of a second site from the Crown Estates Office auction. In the next financial year, the division aims to continue to invest in renewable generation capabilities with the objective of meeting the stated target of achieving 10% of electricity supply from renewable sources by 2010. The Government granted planning permission in May 2004 for the construction of a highly flexible £100 million gas store near Byley, Cheshire.
PPM’s net investment in assets for the year was £129 million, with £117 million (91%) invested in organic growth projects. Of this, more than £100 million was invested in new wind generation, with the construction of Flying Cloud (44 MW), Moraine (51 MW), Mountain View III (22 MW) and Colorado Green (81 MW). All of these windfarms qualified for US Production Tax Credits (“PTCs”) and accelerated tax depreciation benefits, and were commercially operational in the third quarter and contributing to profits. Other growth investments during the year included the purchase of an additional 17% ownership interest in the Alberta gas storage hub, bringing PPM’s total ownership to 57%, and the commencement of a further gas storage development of 7 BCF at the Waha site in west Texas. The project is being developed in phases over six years, with the first phase operational by 2006.
3 Improving Operational Performance
PacifiCorp
Operating profit, excluding goodwill amortisation, increased by $65 million to $943 million, including the delivery of cost efficiencies of $49 million and deferred power costs recovered, which were $23 million lower at $91 million. The first quarter of 2004/05 has started less strongly than our expectations due to a combination of milder weather impacting on residential demand, lower hydro resource and lower thermal plant availability. However, PacifiCorp remains committed to achieving its target of $1 billion EBIT (earnings before interest and tax, excluding goodwill amortisation) in 2004/05.
PacifiCorp is currently pursuing a regulatory programme in all states with the objective of keeping rates closely aligned to ongoing costs. In March 2004, the Wyoming Public Service Commission granted PacifiCorp approximately $23 million of additional annual revenue, reflecting the Commission’s recognition of the investments made by PacifiCorp in support of customer growth in the state. Along with awards earlier in the year of $65 million in Utah, $8.5 million in Oregon, and $3 million in California, this took the total of rate case awards in the year to approximately $100 million of additional annual revenue. These rate cases included full recovery for all new system investments and other new costs. The $27 million Washington general rate case is progressing on schedule with an outcome expected at the end of November 2004. PacifiCorp seeks to maximise its return on equity (“ROE”) within the limits permitted by US state regulators. The outcome of general rate cases conducted by the state regulatory commissions sets the authorised ROE, with each commission establishing its own ROE for PacifiCorp. During the year, the authorised ROE specified by PacifiCorp’s state regulators ranged from 10.5% to 10.9%. Regulatory returns for PacifiCorp at September 2003, the end of the last regulatory reportable period, were approximately 8%.
As a regulated business, PacifiCorp serves some of the fastest growing regions in the western US, which provides an opportunity for further network investment and generation sourcing to ensure reliable service, and extensive expansion plans are underway. Regulatory and other final approvals to build the 525 MW Currant Creek gas-fired station in Utah, were given in March and April 2004, and we have already begun the first phase of construction of this $350 million plant. For the proposed Lake Side plant we are seeking regulatory approval by December 2004. Further opportunities include a potential 1,100 MW in proposed renewable projects and $212 million currently being invested for growth in infrastructure across our six states, including Utah, which has seen strong residential load growth of approximately 4% per annum in recent years. Network investments, such as the increase of 564 MVA of capacity added this year improved underlying system reliability. These systemwide investments have assisted in the delivery of a 16% improvement in reliability over the prior year, excluding major events such as the impact of the extremely challenging winter storms that hit PacifiCorp’s service area. During the same period PacifiCorp has improved its level of safety, reducing lost time accidents by 25%.
In the year, PacifiCorp delivered $49 million of operating efficiencies, including benefits from generation plant performance, managing power costs, and negotiation of fuel contracts. Cumulative operating efficiencies now stand at $266 million and we remain on track to achieve our $300 million savings target in 2004/05.
PacifiCorp today has a proven management strategy to balance power demand and supply with a portfolio of generation and transmission assets, forward physical purchases and financial hedges, delivering a forecast net balanced position for the summer periods of 2004 and 2005. PacifiCorp’s natural gas supply is also fully hedged through 2006 and the company is implementing longer- term supply arrangements to minimise natural gas supply risks for the Currant Creek plant.
6 ScottishPower Annual Report and Accounts 2003/04
Infrastructure Division
The success of Infrastructure Division, our UK wires business, in growing its regulated revenues and controlling its cost base, which reduced by £6 million in the year, helped drive operating profit up £26 million to £394 million. Our Infrastructure Division was rated amongst the top performers in the key area of asset management in an earlier independent study from Ofgem, an accolade that highlights the advances made as the company develops investment programmes around a clear understanding of asset risk and network performance. At the same time, we sought to minimise customer disruption through all weathers, largely successfully, as the Department of Trade and Industry acknowledged in a post-storm investigation.
As the UK’s third largest electricity distribution business, we are set to play a key role in rewiring Britain. The Government agrees more money must be spent on preparing the UK for an increase in electricity supply from renewables as well as strengthening the existing network to meet the needs of the 21st century. We hope to invest at least £1.2 billion in our network in the next five years. In addition, we envisage some £100 million will be invested to accommodate Distributed Generation (“DG”), mainly to link new windfarms to the grid. We remain supportive of Ofgem’s objectives in this area and believe that progress has been made towards the development of acceptable proposals for DG. A related scheme for expanding transmission is underway and preparatory work on stage one, an investment of over £200 million, is well advanced. Further stages still to be approved could see a total investment of £400 million over 10 years, which will be the biggest growth in the UK high voltage network since the 1960s. These investments will increase our regulated asset base and, consequently, returns.
We remain constructively engaged with Ofgem on the 2005 Distribution Price Control Review. Ofgem’s March 2004 consultation document set out the issues, with key areas outstanding, including cost of capital. We will continue to press Ofgem for higher rates of return to reflect correctly the nature of our business and look forward to Ofgem’s initial proposals due at the end of June this year.
UK Division
UK Division, our integrated generation and customer supply business, gained 600,000 customers in the year, bringing the total number of customers to 4.25 million, an increase of 16%. In the first quarter of 2004/05 we continue to make good progress in attracting more new customers. We continue to enjoy the benefit from using a single domestic billing system and this, along with other process improvements, has contributed to us gaining a top two ranking in quality of service ratings in minimising complaints for direct selling and customer transfers. The customer gains were not won lightly and stem from a tough, two-year streamlining of operations to improve customer service, facilitating our strong customer growth and also improving efficiency. Consequently, operating profit, excluding goodwill amortisation, rose by £23 million to £101 million.
UK Division has laid the foundations for increased returns by focusing on reliability and efficiency. Supply activities are being transformed by the 6 Sigma programme which aims to improve all customer handling processes and which delivered revenue and cost benefits of £13 million in the year. We have now extended this programme to our generation activities and expect to see both operational and cost improvements.
Pivotal to the running of our vertically integrated operations is the Energy Management hub whose performance has again underlined our ability to balance customer numbers and the generation capacity required to supply them while delivering competitive prices. The renegotiation or removal of restructuring contracts, inherited at privatisation, is now complete. Last year, an annual cost burden of approximately £25 million (based on 2002/03 market prices) was removed, following the renegotiation of the Nuclear Energy Agreement (with British Energy). The early termination of the Peterhead and Hydro Agreements (with Scottish and Southern Energy) will deliver a future annual saving of approximately £20 million from April 2005. As our customer base grows we continue to explore opportunities to add further gas-fired generation to our generation portfolio.
In addition, renewables are now central to the UK’s future power needs and, as the UK’s leading windfarm developer, ScottishPower is ideally placed to benefit. The planning approval for Black Law in Scotland’s Central Belt in February 2004 was the largest consent given for an onshore windfarm in the UK and our experience in building windfarms gives the division a vital skills advantage in siting, environmental impact assessment and design. We were pleased to commission the 30 MW Cruach Mhor windfarm in March 2004. Our offshore wind activity is also progressing with the allocation of a second site from the Crown Estates Office auction.
The £100 million, 6 BCF gas storage facility near Byley, Cheshire will help provide greater security of supply, as gas imports to the UK are expected to rise. Byley’s short cycle time will also enable it to respond to the expected increase in overall demand and price volatility.
Our focus on efficiency has also driven improvements in our fuel and logistics processes. Coal deliveries, under the new Clydeport contract started at Hunterston and Rosyth in April 2004, are expected to deliver savings of £8 million in the financial year 2004/05 and up to £10 million per annum thereafter. Additionally, on completion of successful trialing of co-burning, full biomass operations at Longannet and Cockenzie are planned to commence this year with expectations to deliver approximately £5 million of annual benefit through Renewables Obligation Certificates (“ROCs”).
The latest proposals for the National Allocation Plan under the EU Emissions Trading Scheme published on 6 May 2004 remain in line with our expectations and continue to show the burden of carbon reduction being placed on the power sector. Whilst supporting the overall Government objective of achieving a lower carbon economy, ScottishPower continues to argue that
ScottishPower Annual Report and Accounts 2003/04 7
Chief Executive’s Review
the scheme must encourage sufficient investment in new generation to ensure the ongoing security of supply in the UK.
PPM
PPM, our competitive US energy company, continues to build on its impressive record. Operating profit, excluding goodwill amortisation, rose by $18 million (41%) to $63 million, with increased contributions from gas storage, optimisation of assets and its steadily growing share of the US wind power market.
PPM accounted for almost a third of new wind developments in the US in calendar year 2003, adding control of 528 MW (504 MW in the financial year 2003/04) to its portfolio, which now totals around 830 MW of renewable energy currently under its control. PPM is now pursuing its immediate goal of developing another 500 MW of wind projects. Their completion depends partly on the extension of the PTCs, expected to be introduced this year, which would keep PPM on track for its goal of 2,000 MW by 2010. In the longer-term, PPM is well placed to take full advantage of the 8,000 MW of potential projects and sites already ear-marked for development. In line with the group’s prudent energy management strategy, PPM has already sold forward approximately 80% of its wind power in contracts of between 10 and 25 years, locking in a regular “annuity” value.
During the year, an increasing component of PPM’s revenues came from its gas storage and hub services business, serving North America from bases in Texas and Canada, which include operating or contracting activities for gas storage and selling capacity forward. Our view is that gas prices will remain volatile, with tight supply and demand, enhancing the value of PPM’s owned and contracted gas storage facilities which now total 67 BCF. In addition, as part of PPM’s increased origination activities, the number of large wholesale gas customers has increased by approximately 50% over the past year and includes major refineries and municipalities.
Health and safety continues to be our top priority and during the year we reviewed our health and safety policy and standards. ScottishPower has a good health and safety record, but it is my ambition to achieve world-class health and safety performance throughout the company.
Our new policy and standards reflect our determination to achieve our goal of creating a positive and productive environment that is free from injury or illness and causes no harm to our employees, customers or the general public.
We have stepped up employee involvement and training, launched behavioural safety auditing and we have been working with our contractors to ensure they share our commitment to health and safety. We have also improved the sharing of best operational practices across our businesses.
Looking ahead our policy will be to foster a sense of common purpose to create a culture that will drive excellent and sustainable health and safety performance.
5 Corporate Social Responsibility
During the year we have continued our commitment to building a strong business which creates benefits for customers, employees, shareholders, communities and the environment.
We were pleased to be ranked 12th out of 140 companies in Business in the Community’s 2004 Corporate Responsibility Index and to win the Edison Electric Institute’s International Award 2004, under the theme of “Progress Through Responsibility”.
In recognition of ScottishPower’s support for communities, I was asked to lead a Commission for the UK Government to investigate the development of a Youth Volunteering Strategy. I look forward to this role and believe there is huge potential for a national volunteering programme that enables young people to fulfil their potential and help to build strong and cohesive communities throughout the UK.
At ScottishPower we recognise that our people are our greatest asset and employee feedback has been incorporated into the company’s performance management system through our employee survey tools.
This group-wide employee survey measures how our employees feel about their working environment. The results are monitored by the Executive Team and are used as a basis for action to remove barriers to productivity and increase employee satisfaction.
We remain committed to developing talent at all levels within the organisation, supporting employee study by providing workplace and home-based learning opportunities and tailored management development programmes. Throughout the company we strive to recognise and celebrate the achievements of our people as we continue to build our business for the future.
Looking ahead, we are well placed to exploit fully the good opportunities we see for profitable growth on both sides of the Atlantic. Increasing demand and the need for more reliable and sustainable energy present attractive opportunities for organic growth and higher returns. We remain confident that our strategy will create further value for shareholders.
| /s/ Ian Russell |
| Ian Russell, Chief Executive 25 May 2004 |
8 ScottishPower Annual Report and Accounts 2003/04
Scottish Power plc (“ScottishPower”), a public limited company registered in Scotland, is an international energy company listed on both the London and New York Stock Exchanges. Through its operating subsidiaries, the company provides in excess of 5.8 million electricity or gas services to homes and businesses in the western US and across the UK. It provides electricity generation, transmission, distribution and supply services in both countries. The company’s US activities extend to coal mining and gas storage, including gas facilities in western Canada and in Texas. In Great Britain, ScottishPower also stores and supplies gas. In the year to 31 March 2004, the sales revenues of the group were £5.8 billion ($10.7 billion).
Following its creation upon privatisation in 1991, ScottishPower developed by both organic growth and strategic acquisitions in the British electricity, gas and telephony markets - and through its November 1999 merger with PacifiCorp in the US. During 2001/02, the group was redefined as an international energy business, exiting non-strategic activities in the US and UK, demerging the UK telecommunications and internet business, Thus, to the company’s shareholders and, in April 2002, selling the UK water and wastewater company, Southern Water. From 2002/03, ScottishPower has focused on its strategic aim of becoming a leading international energy company.
Strategic Context
ScottishPower’s strategy is to become a leading international energy company; managing both regulated and competitive businesses in the US and the UK to serve electricity and gas customers. The regulated businesses provide a base for steady growth through consistent investment and proven skills in operational and regulatory management. In its competitive businesses where the group has local market knowledge and skill advantages, it seeks to grow its market share and to enhance margins through the integration of generation, energy management and customer services, again underpinned by best-in-class operational performance. The aim is to support the growth and development of both regulated and competitive businesses through a balanced programme of capital investment which will deliver organic growth. Growth will arise from investment in new generation, networks and gas storage assets. It will also be sought through competitive market share gains and selective acquisitions of smaller operations that complement the group’s business and will accelerate its organic growth. Shareholder value will be created through an investment programme assessed on a risk-adjusted returns basis. Individual investments are expected to be earnings enhancing and supportive of the aim of retaining an A– credit rating for the group’s principal operating subsidiaries.
The strategy is delivered through four businesses, each clearly focused on its strategic priorities:
| • | PacifiCorp |
| • | Infrastructure Division |
| • | UK Division |
| • | PPM |
In each of the US and the UK, there is one business operating under regulation and one in competitive market conditions.
ScottishPower Annual Report and Accounts 2003/04 9
Business Review Description of Business
In the US, PacifiCorp operates as a regulated electricity business and the competitive energy business is PPM Energy, Inc. (“PPM”). Both are subsidiaries of PacifiCorp Holdings, Inc. (“PHI”) a non-operating, US holding company, itself an indirect wholly-owned subsidiary of ScottishPower. PHI is also the parent company of PacifiCorp Group Holdings which owns the shares of subsidiaries not regulated as domestic electricity providers, including PacifiCorp Financial Services, Inc.
In the UK, the regulated Infrastructure Division operates electricity transmission and distribution subsidiaries of the wholly-owned UK holding company Scottish Power UK plc (“SPUK”). Other subsidiaries comprise the group’s competitive energy business, the UK Division, covering its British Isles generation assets, commercial and energy management activities and energy supply business units.
In November 1999, PacifiCorp and ScottishPower completed a merger under which PacifiCorp became an indirect subsidiary of ScottishPower. As a result of the merger, PacifiCorp developed and implemented significant organisational and operational changes arising from the strategic decision to focus on its electricity businesses in the western US and embarked upon a continuing programme of efficiency improvements.
Principal Business Activities
PacifiCorp is a regulated electricity company operating in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. As a vertically-integrated electricity business, PacifiCorp owns or controls fuel sources, such as coal and natural gas, and uses these fuel sources, as well as wind, geothermal and hydroelectric resources, to generate electricity at its power plants. This electricity, together with electricity purchased on the wholesale market, is transmitted over a grid of transmission lines throughout PacifiCorp’s six-state region and is then transformed to lower voltages and delivered to end-use customers through PacifiCorp’s distribution system. PacifiCorp conducts its retail electricity utility business as Pacific Power and Utah Power, and engages in electricity sales and purchases on a wholesale basis under the name PacifiCorp. The subsidiaries of PacifiCorp support its electricity utility operations by providing coal mining facilities and services and environmental remediation.
The western US energy market is experiencing growth in demand due to both increased customer numbers and underlying load growth. PacifiCorp continued its energy hedging strategy, maintaining a balanced loads and resources position through 2003. PacifiCorp has hedged its forecast load and resource balance and price exposure for 2004/05 and for summer 2005, when demand is expected to be supported by the commissioning of the first phase of the 525 MW Currant Creek plant in Utah. PacifiCorp also continued to invest in support of network safety, reliability and high-level performance, including targeted investments in areas of high demand growth. However, severe storms in late December 2003 and early January 2004 impacted the PacifiCorp network in northern Utah and parts of Oregon and California, increasing costs and leading to voluntary goodwill payments to those Utah customers who were without power for extended periods.
Retail Electricity Sales
PacifiCorp serves approximately 1.6 million retail customers in service territories aggregating about 135,000 square miles in portions of six western states. The geographical distribution of PacifiCorp’s retail electricity operating revenues for the year ended 31 March 2004 was Utah, 39%; Oregon, 32%; Wyoming, 13%; Washington, 8%; Idaho, 6%; and California, 2%. In August 2003, PacifiCorp announced that it was discontinuing efforts to sell its California service area to the Nor-Cal Electric Authority and committed itself to continue to serve its more than 44,000 customers in Yreka, Crescent City, Alturas, Mt. Shasta and the surrounding communities.
The PacifiCorp service area’s diverse regional economy mitigates exposure to economic swings. In the eastern portion of the service area, mainly Utah, Wyoming and south eastern Idaho, customer demand peaks in the summer when cooling systems and irrigation are heavily used. The principal industries are manufacturing, health services, recreation and mining or extraction of metals, coal, oil, natural gas, phosphates and elemental phosphorus. In the western part of the service territory, mainly consisting of Oregon, south eastern Washington and northern California, customer demand peaks in the winter months due to heating requirements and the economy generally revolves around agriculture and manufacturing, with pulp and paper, lumber and wood products, food processing, high technology and primary metals being the principal industries. During 2003/04, no single retail customer accounted for more than 2% of PacifiCorp’s retail electricity revenues and the 20 largest retail customers accounted for 13% of retail electricity revenues. Trends in energy sales by class of customer are set out in Tables 3, 5 and 6 (page 31).
PacifiCorp serves some areas of rapidly changing population size and economic activity. In particular, a substantial part of the eastern service territory is in Utah and Idaho, states expected to be among the top ten states in the US for growth during the next few years. Additionally, recent warm summer temperatures are causing residential customers to install central air conditioning systems and are contributing to a faster summer peak growth. Commercial sales are positioned for growth in the eastern portion of the service territory, particularly Utah, because of strong population and economic viability and through Utah’s central role in the manufacture, distribution and delivery of goods to surrounding western states. Wyoming is experiencing increasing industrial activity in its energy-related sectors, with increasing exploration and rig counts suggesting a positive trend in PacifiCorp’s future sales to the industrial sector in the state.
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Oregon, which has been experiencing recessionary conditions, nonetheless contains a number of communities showing high levels of growth suggesting the likelihood of an increasing pace of economic development and recovery across PacifiCorp service territories.
For the five years to 31 March 2009, the underlying annual growth in retail MWh sales in PacifiCorp’s franchise service territories is estimated to be in the range of 1.5% to 2.6%, dependent upon factors such as economic growth, changes in customer numbers, weather, the potential effects on demand resulting from conservation efforts and changes in price. If prices increase in the region, demand growth over the region may slow.
Power Production and Fuel Supply
PacifiCorp owns or has interests in generating plants with an aggregate nameplate rating of 8,420 MW and plant net capability of 7,987 MW, see Table 1 (page 30). During 2003/04, approximately 73% and 5% of PacifiCorp’s energy requirements were supplied by its thermal and hydroelectric generation plants respectively. The remaining 22% was obtained primarily through purchased power. The share of PacifiCorp’s energy requirements generated by its own plants will vary from year-to-year and is determined by factors such as planned and unplanned outages, availability and price of coal and natural gas, precipitation and snowpack levels, environmental considerations and the market price of electricity. PacifiCorp will make use of existing long-term purchase contracts, and expects to choose appropriate cost-effective resources to meet the balance of its customer demand through new long- and short-term purchase arrangements, including those covering some 91 MW of wind power.
At 31 March 2004, PacifiCorp had 220 million tons of recoverable coal reserves that are mined by PacifiCorp’s mining affiliates and are dedicated to nearby PacifiCorp-operated generation plants, see Table 2 (page 30). During 2003/04, these mines supplied some 30% of PacifiCorp’s total coal requirements. Coal is also acquired through long-term and short-term contracts. Thirteen long-term coal contracts accounted for 68% of the overall 2003/04 requirements. The contract terms range from one to 19 years. PacifiCorp has also entered into long-term, fixed-price natural gas contracts to meet the forecasted needs of its existing natural gas-fired electricity generation plants to the end of calendar year 2006. Natural gas transportation capacity was purchased to meet the needs of the Currant Creek project, which is expected to start up in June 2005, and PacifiCorp has purchased most of its calendar year 2006 forecasted gas supply needs for the Currant Creek project.
To manage future generation needs and meet environmental objectives, PacifiCorp developed an Integrated Resource Plan (“IRP”), filed in January 2003 and updated in October 2003. The IRP is reviewed and updated every two years and provides a framework which will allow PacifiCorp to continue to select optimal solutions from a mix of renewable, thermal, market purchase and demand side management choices and will guide specific “build or buy” decisions made dependent on permitting, siting, emissions, cost recovery and economic conditions. Regulators in many of the states in which PacifiCorp operates have acknowledged the 2003 IRP. Costs incurred by PacifiCorp to provide a service to its customers are expected to be included as allowable costs for ratemaking purposes. However, under the US “regulatory compact”, PacifiCorp must demonstrate to regulators that the incurred costs are both reasonable and necessary to the provision of safe, adequate, reliable and efficient electricity utility services to its retail customers and that the decisions were made in a prudent manner.
Action items from PacifiCorp’s 2003 IRP have been pursued in the Requests for Proposals (“RFP”) process which seeks to identify PacifiCorp’s future resource mix though a programme coordinated with stakeholders in the six states it serves. From the first of the RFPs, PacifiCorp determined that the construction of a new 525 MW gas-fired plant in Utah, would be the lowest risk and most economical 2004/05 resource category choice to meet future generation needs. The plant will be named Currant Creek. The Utah Public Service Commission (“UPSC”) has given its approval for construction of the plant and the Utah Division of Air Quality issued its final approval order in May 2004. The plant is expected to come on-line in two phases over 2005 and 2006. On 10 May 2004, PacifiCorp announced that, following a thorough review of proposals submitted, it had identified the Summit Vineyard LLC proposal for the construction of a 534 MW Lake Side Power Plant near Salt Lake City, Utah as the best option to meet the long-term resource requirements of its customers. PacifiCorp’s filing for a Certificate of Convenience and Necessity for the development could take up to six months to complete and is intended to facilitate a summer 2007 introduction of the plant. In February 2004, PacifiCorp issued a further RFP seeking up to 1,100 MW of new renewable resources across its service territories over the next seven years.
Wholesale Sales and Purchased Electricity
In addition to its base of thermal, renewable and hydroelectric generation assets, PacifiCorp uses a mix of long-term, short-term and spot-market purchases to balance its load and wholesale obligations. PacifiCorp enters into wholesale purchase and sale transactions to provide hedges against periods of variable generation or variable retail load. Generation varies with the level of outages or transmission constraints and retail load varies with the weather, distribution system outages and the level of economic activity. During the year ended 31 March 2004, 22% of PacifiCorp’s energy requirements were supplied by electricity purchased under short- and long-term arrangements. For the year ended 31 March 2003, 23% of PacifiCorp’s energy requirements were supplied by purchased electricity under short-and long-term purchase arrangements. During 2003/04, there was a slight decline in short-term wholesale sales and a broadly parallel reduction in short-term purchases with an overall increase in the use of owned generation and longer-term
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purchases. PacifiCorp’s wholesale transactions are integral to its retail business, providing for a balanced and economically hedged position and enhancing the efficient use of its generating capacity over the long term. PacifiCorp’s transmission system is available for common use consistent with open access regulatory requirements and connects with market hubs in the Pacific Northwest to provide access to what is normally low-cost hydroelectric generation and also to the south western US, which provides access to normally higher-cost fossil-fuel generation.
Under the requirements of the Public Utility Regulatory Policies Act of 1978, PacifiCorp purchases the output of qualifying facilities constructed and operated by entities that are not public utilities. During 2003/04, PacifiCorp purchased an average of 108 MW from qualifying facilities, compared to an average of 101 MW in 2002/03.
Three wholly-owned subsidiaries of SPUK – SP Transmission Limited, SP Distribution Limited and SP Manweb plc – are the “asset-owner companies” holding the group’s UK regulated assets and transmission and distribution licences. A further wholly-owned subsidiary of SPUK – SP Power Systems Limited (“PowerSystems”) – provides asset management expertise and conducts the day-to-day operation of the networks.
Principal Business Activities
The asset-owner companies act as an integrated business unit to concentrate divisional expertise on regulatory issues and investment strategy. PowerSystems implements work programmes commissioned by and agreed with the asset-owner business. Strict commercial disciplines are applied at the asset owner-service provider interface, with PowerSystems operating as a contractor to the transmission and distribution business unit. An integrated senior management team within the Infrastructure Division applies the benefits of growing expertise in asset ownership, financing and operational service provision to the management of the group’s regulated networks businesses in both the UK and the US.
Transmission and Distribution
ScottishPower owns and manages a substantial UK electricity transmission and distribution network which extends to over 115,000 km, with 67,100 km of underground cables and 48,400 km of overhead lines, comprising both the distribution system to customers in its two authorised areas and, in Scotland, its high-voltage transmission system (132 kilovolt (“kV”) and above, including those parts of the England-Scotland interconnector which are in its Scottish authorised area). Table 9 (page 32) shows key information with respect to the division’s transmission and distribution services in 2003/04. These networks are operated under licences issued by the Gas and Electricity Markets Authority (“the Authority”) and held by the transmission and distribution businesses, which are entitled to charge for the use of the systems on terms approved by the Authority under various price control formulae.
The management focus of the transmission and distribution business is to outperform allowed regulatory returns from the provision of efficient, coordinated and economical networks which are open to licensed users on a non-discriminatory basis (in order to facilitate competition in generation and supply) and operated to approved standards of safety and reliability. The business is also engaged in continuing work with the Office of Gas and Electricity Markets (“Ofgem”) and the rest of the industry to develop the price control framework to allow increased investment to secure the long-term safety, reliability and sustainability of the electricity infrastructure in Great Britain and to invest in network development to support the UK Government’s planned expansion of renewable generation.
The income derived from the distribution business is dependent on the demand for electricity by customers in the authorised areas. Demand for electricity is affected by such factors as growth and movements in population, social trends, economic and business growth or decline, changes in the mix of energy sources used by customers, weather conditions and energy efficiency measures. Tables 10 and 11 (page 32) set out the demand in gigawatthours (“GWh”) by customer type within the broadly stable levels of electricity transported over the distribution systems in the ScottishPower and Manweb home areas during the five most recent financial years.
Asset Management
Within the PowerSystems business unit, the focus continues to be on cost-effectiveness and service quality improvement. Its principal business activities involve the construction and refurbishment of the UK transmission and distribution systems, their maintenance and related fault repair. PowerSystems acts as the major service provider to the ScottishPower transmission and distribution business and as the primary customer contact agent for network-related matters. PowerSystems continues to focus strongly on the efficient delivery of these services under contract. The regulatory framework provides financial incentives to improve network performance and customer satisfaction. PowerSystems is focused on maximising the financial benefit to be obtained from these incentives over the course of the current price control period.
Some 23% of the division’s investment programme is devoted to organic growth areas such as new customer connections and network reinforcement. PowerSystems has continued to maintain a joint venture with Alfred McAlpine Utility Services Limited, called Core Utility Solutions Limited, to take advantage of the opportunities presented by the requirement for competitive provision of connections to distribution networks.
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The UK Division operates in gas and electricity markets which became fully competitive with the ending of residual price controls on 31 March 2002; although Ofgem continues to enforce licence conditions and regulate quality of service. The division comprises five wholly-owned subsidiaries: ScottishPower Generation Limited owns and operates the power stations and other generation assets in the British Isles and holds the group’s generation licence; ScottishPower Energy Management Limited and ScottishPower Energy Management (Agency) Limited deal in gas and electricity at the wholesale level and in the commercial instruments and agreements which constitute the market balancing mechanisms for the competitive energy market in the UK; ScottishPower Energy Retail Limited is the gas and electricity supply company and holder of the group’s supply licences, managing pricing, selling, billing and receipting for gas and electricity supply to both business and domestic customers and dealing with enquiries arising in the course of this business; and SP Dataserve Limited is the data management and metering company, managing the data processes which underpin customer registration through to billing and settlement.
The divisional management team oversees activities across the energy value chain, maximising value from a diverse generation portfolio through to a national customer base of 4.25 million, via an integrated commercial and energy management activity that acts to balance and hedge energy needs. In 2003/04, wholesale energy prices recovered from the historic lows of 2002/03 although, in light of the emphasis on a market-based framework for energy policy set out by the UK Government in February 2003, wholesale energy markets face the prospect of continuing structural and contractual changes. As an active market participant, the division engages fully in regulatory and contractual debate and in the consultation processes following the Government’s review of energy policy. In the meantime, the division aims to leverage the benefits of its flexible generation asset base and commercial operations to deliver sustained earnings through improved business processes and customer service and to develop its position in renewable generation.
Principal Business Activities
The UK Division operates ScottishPower’s generation assets in the British Isles, manages the company’s exposure to the wholesale electricity and gas markets and is responsible for energy supply: the sales and marketing of electricity and gas to customers throughout Great Britain, together with the associated customer registration, billing and receipting processes and handling enquiries in respect of these services.
Power Plant Portfolio, Fuel Strategy and Generation Sales
The UK Division operates some 5,400 MW of generating capacity, see Table 8 (page 32) comprising coal, gas, hydroelectric and wind power generation assets, giving the division a particularly flexible portfolio. Acquisition of additional thermal generation capacity is kept under continuing review but purchases will only be made at value-enhancing prices and the current market is characterised by over-capacity. The restated public policy emphasis on renewable generation and the extension to 2015 of the Renewables Obligation Certificates scheme targets provide the context for continued expansion of the windfarm business which, at 31 March 2004, had operational windfarms totalling 158 MW, planning applications for a further 920 MW and environmental assessments begun on around 560 MW of further potential sites to ensure that the company target of 10% of supply from renewables by 2010 is met.
ScottishPower’s fuel purchasing strategy is based upon the objective of achieving competitive fuel prices while balancing the need for security and flexibility of supply. The major components of the fuel portfolio are coal and gas, both fuels being sourced through a combination of long-term contracts and shorter-term trading. The division has three long-term contracts with terms of greater than five years for supply from major gas fields.
Generation output is managed in order to hedge risk and optimise the position in the balancing market. In 2003/04, some 19 terawatt hours (“TWh”) were despatched, both to contribute towards the approximately 33 TWh of retail and wholesale demand provided by the division and to maintain export volumes through the interconnectors to England & Wales and to Northern Ireland.
Energy Management and Commercial Arrangements
In addition to its own generation capacity and long-term bulk gas contracts the UK Division has access to additional generation under contract. Through its commercial and energy management operations, the division uses medium and short-term contractual arrangements to complete its energy purchase requirements and to sell its generation output into the electricity market in Scotland and, through the interconnectors, to England & Wales and to Northern Ireland. The Energy Bill intended to facilitate a Great Britain-wide market through the British Electricity Trading and Transmission Arrangements (“BETTA”) was introduced into Parliament in November 2003, although the new arrangements are now not expected to become effective until April 2005 at the earliest. BETTA is expected to have only a modest impact on end-user prices and the focus of consultation is now on transmission charging in a Great Britain-wide market, particularly in the light of the policy emphasis on renewables.
Through its activities in the electricity, gas and coal markets, ScottishPower’s energy management business secures competitive advantage for the UK Division through hedging and optimising its position across the energy value chain, continuously evaluating and managing risk exposure. ScottishPower’s Hatfield Moors gas storage site enhances the flexibility of the division’s energy management position, both in meeting peak demands of supply customers and responding to the volatility of gas prices between midweek and weekends. In
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addition, the bulk gas contracts allow the gas to be sold out or used in the division’s power stations, giving yet more flexibility. A planning application for a 6 billion cubic feet (“BCF”) gas storage facility at Byley, Cheshire was approved in May 2004, following a public inquiry in late 2002.
The New Electricity Trading Arrangements, introduced into England & Wales in March 2001, provided for a direct contracting, pay-as-bid process between generators and suppliers, with imbalances between actual and contracted positions settled through a balancing mechanism intended to lead to more cost-reflective prices and more effective management of risk. In this context of a fully competitive energy market, the division has renegotiated or ended a number of long-term contracts put in place before privatisation in 1991 under which it was obliged to pay non-market-based rates for electricity from the nuclear plants of British Energy (“BE”) and the Peterhead power station and hydro plants of Scottish and Southern Energy (“SSE”). Necessary regulatory approvals have been received and the revised arrangements with BE took effect in November 2002, providing a benefit of some £25 million a year. Removal of the relevant contracts with SSE will take effect from April 2005, providing a further anticipated saving of around £20 million a year from 2005 onwards.
Energy Supply
Since September 1998 when, under the provisions of the Electricity Act, competition was extended to residential electricity customers, the strategic focus of the ScottishPower energy supply business has been the defence of its core markets, residential and small business customers in the ScottishPower and Manweb home areas, whilst seeking profitable additional business outside these historical regional boundaries. Retention of home area residential customers stands at 60% whilst targeted sales efforts, strategic marketing alliances, such as NESTMakers, the partnership with Sainsbury’s and the use of e-commerce channels have helped develop a Britain-wide customer base which now stands at 4.25 million energy accounts. The business improvement programme introduced in 2001 continues to drive improvements across the retail supply business and has helped to deliver increased direct debit penetration and reduced customer churn rates in addition to cost benefits in areas such as billing, debt and customer registration business processes.
Metering and Data Management
In the competitive energy market SP Dataserve Limited (“Dataserve”) operates end-to-end process and data management in order to maximise efficiencies in the provision and control of registration and metering data for ScottishPower and other agency arrangements. Data management covers the establishment of new customers, maintenance of existing customers and accuracy of energy settlement. To effectively manage gas and electricity customers, Dataserve has continued to contribute to improvements in billing performance through the management of the agents, who provide much of the data.
PPM, the group’s competitive US energy business, is a fast-growing energy provider, with operating assets in eight US states and in Canada. Its diverse portfolio, focus on wind power and moderate risk approach position PPM for continued earnings growth in 2004/05. PPM commenced substantive operations in 2001 (operating until January 2003 as PacifiCorp Power Marketing, Inc.) and is growing through a strategic focus on clean energy; concentrating on renewable power, natural gas storage and hub services and gas-fired generation.
Principal Business Activities
PPM’s principal assets are thermal and renewable generation resources and natural gas storage facilities, including gas storage assets in western Canada and Texas. PPM creates value by securing quality assets at strategic locations and by locking in value with long-term contracts with creditworthy customers. Integration of plant operations, contract dispatch and energy management add additional value. The optimisation benefits come from displacing plant operations with low-priced electricity purchases, selling the displaced gas or placing it in storage, as well as using transmission and contract delivery flexibility to manage locational price differences in both gas and electricity. PPM aims to leverage the benefits of its flexible asset base and contracts to extract value across gas and electricity.
Power Production and Wholesale Sales
PPM has more than 1,600 MW of operating assets currently under its ownership or control and, of that, PPM has full economic interest in 1,368 MW, see Table 7 (page 31). PPM balances its supply and sales, selling a substantial amount of its supply forward under long-term contracts. In its electricity business, PPM serves a wide variety of wholesale energy customers including municipal agencies, public utility districts and investor-owned utilities. During 2003/04, the number of long-term customers served by PPM’s wholesale electricity business grew from 6 to 18. These customers are primarily located in wholesale energy markets served by the 1.8 million square mile Western Electricity Coordinating Council service territories in the western US and the Mid-Continent Area Power Pool service territories in the upper midwest US.
Wind Power
PPM is the second largest provider of wind energy in the US. Six projects were completed in December 2003 bringing the total added during the calendar year to 528 MW and the total wind power under PPM’s control to more than 830 MW. PPM continues to place much of its renewable energy output under long-term contracts. For example, all output from the new 162 MW Colorado Green windfarm has been sold under a 15-year agreement to supply the Public Service Company of Colorado. PPM has also developed the 51 MW Moraine Wind Power
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Project in southwest Minnesota in conjunction with a long-term power sales agreement signed with the regional regulated utility, Northern States Power Company, and completed the development of the 44 MW Flying Cloud Wind Project in Iowa, which includes a 15-year agreement to sell power to Interstate Power & Light, a subsidiary of Alliant Energy. Approximately 80% of the wind power under PPM’s control has been sold under long-term contract with the balance hedged under multi-year forward power sales.
Gas Storage and Hub Services
PPM’s two major gas storage facilities are in Alberta, Canada and in Katy, Texas. Each is connected into substantial pipeline networks serving well-diversified customer bases under firm, long-term and short-term contract arrangements. In addition to the 44 BCF of gas storage capacity under its ownership during calendar year 2003, PPM has increased its available gas storage capacity by 23 BCF for calendar year 2004 through contracting for capacity in third-party storage facilities in western Canada, Texas and California. This capacity will be used, along with existing facilities, to extend PPM’s energy management and hub services and represents one of a number of development opportunities identified to grow PPM’s gas storage business at selective locations over the next several years. PPM also has begun development of a 7.2 BCF high-deliverability salt cavern gas storage project in west Texas.
US Businesses PHI and its subsidiaries had 6,704 employees at 31 March 2004, of which PacifiCorp and its subsidiaries had 6,507 and PPM and its subsidiaries 194. Approximately 58% of the employees of PacifiCorp and its mining subsidiaries are covered by union contracts, principally with the International Brotherhood of Electrical Workers, the Utility Workers Union of America and the United Mine Workers of America. In the company’s judgement, employee relations in the US businesses are satisfactory.
UK Businesses ScottishPower and its UK subsidiaries had 8,117 employees, at 31 March 2004. Of these, 3,324 were employed in the Infrastructure Division and 4,793 in the UK Division. Approximately 56% of employees in the UK are union members, and 79% are covered by collective bargaining arrangements. In the company’s judgement, employee relations in the UK businesses are satisfactory.
Human Resources Strategy
In 2003/04, plans were developed and implemented to give effect to the human resources strategy approved by the Board in July 2002, which aims to ensure that the business achieves superior results through the high performance of its employees. This is being achieved by strategic efforts to ensure that, wherever they work across the group, employees share a consistent, positive experience of working for ScottishPower which encourages and supports high personal performance. The key strategic initiatives to support the strategy include a strong commitment to leadership development, talent management to build organisational competencies and succession, a strong emphasis on continuously improving performance in health and safety, and efforts to improve employee engagement through a positive working climate.
A new group health and safety governance process was approved by the Executive Team in November 2002 and was implemented in 2003/04, with the Group Health & Safety Executive Committee composed of US and UK members meeting on a quarterly basis. Following extensive consultation and internal communication, a new group health and safety strategy was implemented in 2003/04. As part of the strategy, a new Group Health & Safety Framework composed of a new Group Policy and Health & Safety Standards was also approved for application group-wide. During November and December 2003, baseline assessments were undertaken using the new assessment protocol to measure the performance of business units against standards set on a world-class health and safety scoring scale.
Employee Consultation
An annual survey is conducted across all businesses to provide a measure of employees’ perception of the company’s direction and their sense of empowerment, value, training and development and of manager communication. Survey results are shared with all employees, reviewed by the Executive Team and used in each business to set targets and action plans for the following year. In addition, individual businesses use surveys and other tools to understand the issues that fall within their specific areas of responsibility and regular consultation takes place using a variety of means including monthly team meetings, team managers’ conferences, business unit road shows, safety committees, presentations, focus groups and employee magazines. Senior managers across the business meet with a cross-section of employees on a regular basis and with trade union representatives in joint consultations on issues of mutual interest.
Further details of group workplace policy and performance can be found in the ScottishPower Environmental and Social Impact Report and the ScottishPower Workplace Performance Report. Both are available on the ScottishPower website. The company also operates a number of all-employee share plans (see page 75).
ScottishPower recognises the need for a responsible business to embrace a wider role in society and to engage fully with shareholders, staff, communities, customers and other opinion formers. It aims to do this transparently, through an international framework, to ensure that key
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principles are translated into action. This framework comprises overall international visionary goals; and specific goals for the US and UK. Performance towards meeting these goals is tracked through carefully chosen Key Performance Indicators, closely related to business unit objectives. ScottishPower’s strategy is to become a leading international energy company. Hence, it must strive to achieve a balance between various needs including securing energy supply now and into the future, keeping energy affordable and minimising its impact on the environment.
Policy frameworks in the US and UK have common elements, particularly in using market instruments for air quality regulation and supporting renewables and energy efficiency measures. In the US, numerous Congressional proposals on “multi-pollutant” regulation feature tradable credits intended to provide cost-efficiency and flexibility in meeting emissions limits. Efforts continue in Congress to extend the renewable energy production tax credit, which helps to make new wind projects price-competitive in many US electricity markets. Also, efforts continue to create viable markets for renewable generation at the state level, most notably in California. The UK Government and the European Commission (“EC”) are developing firm proposals for the implementation of the European Union (“EU”) Emissions Trading Scheme which is scheduled to bring a mandatory emission trading regime into force in 2005. The UK Energy White Paper, published in February 2003, doubled the UK renewables target of 10% by 2010 to 20%, to be achieved by 2020. Energy saving and energy services received a boost, while resources were identified to support new clean coal. In Scotland, the Scottish Executive has announced the target of achieving 40% of electricity generation from renewable sources by 2020. This is being carried out at a time when network operators and the UK regulator, Ofgem, are engaging in discussions which recognise the need to set network upgrades in the context of future network development for renewables and embedded generation.
The group continues to develop specific policies to respond to these regulatory challenges, aiming to grow its business sustainably in new energy markets, to invest in renewables and clean-coal technology and to ensure that customers benefit from innovations in energy efficiency. It also aims to manage existing coal-fired assets responsibly, applying appropriate abatement technologies to reduce its environmental footprint whilst supporting security of supply and affordability of power for its customers. The lines of accountability for environmental policy are focused through the policy making Energy and Environment Committee, chaired by the Chief Executive and with direct reporting lines to ScottishPower’s Executive Team.
Further details of group environmental policy and performance can be found in the ScottishPower Environmental and Social Impact Report and the Environmental Performance Report. Both are available on the ScottishPower website.
In order to encourage comparability, the group uses the London Benchmarking Group (“LBG”) model to evaluate its community support activity groupwide. The LBG model is a standard for community reporting adopted by over 80 leading UK companies and ScottishPower’s use of the model is reviewed each year by the LBG to help ensure the evaluation principles are correctly and consistently applied. During 2003/04, ScottishPower companies contributed £6.2 million in community support activity. This incorporated £600,000 categorised by the LBG model as charitable gifts, £4.8 million of community support activity categorised as community investment and £760,000 categorised as commercial initiatives in the community given in cash, through staff time and in-kind donations by the company’s US and UK operations. An additional £1.2 million of charitable support was made through the PacifiCorp Foundation for Learning, which is fully endowed by ScottishPower companies.
Further details of group community engagement policy and performance can be found in the ScottishPower Environmental and Social Impact Report and the Marketplace & Community Performance Report. Both are available on the ScottishPower website.
9 Description of the Company’s Property
US Businesses The US properties consist primarily of generating facilities, electricity transmission and distribution facilities, coal mines and a number of office facilities. Substantially all of PacifiCorp’s electricity plants are subject to the lien of PacifiCorp’s Mortgage and Deed of Trust.
PacifiCorp owns or has an interest in 54 hydroelectric generating plants. These have an aggregate nameplate rating of 1,077 MW and plant net capability of 1,164 MW. It also owns or has interests in 16 thermal-electricity generating plants with an aggregate nameplate rating of 7,310 MW and plant net capability of 6,790 MW. PacifiCorp also jointly owns one wind power generating plant with an aggregate nameplate rating of 33 MW and plant net capability of 33 MW. Table 1 (page 30) sets out key aspects of PacifiCorp’s existing generating facilities. These generating facilities are interconnected through PacifiCorp’s own transmission lines or by contract through the lines of others. Substantially all of PacifiCorp’s generating facilities and reservoirs are managed on a coordinated basis to obtain maximum load carrying capability and efficiency. Portions of PacifiCorp’s 73,000 miles of transmission and distribution networks are located, by franchise or permit, upon public lands, roads and streets and, by easement or licence, upon the lands of other third parties. Table 4 (page 31) sets out further information regarding the PacifiCorp networks.
PacifiCorp’s coal reserves are described in Table 2 (page 30). Most are held pursuant to leases from the federal government through the Bureau of Land Management and from certain states and private parties. The leases generally have
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multi-year terms that may be renewed or extended and require payment of rentals and royalties. In addition, federal and state regulations require that comprehensive environmental protection and reclamation standards be met during the course of mining operations and upon completion of mining activities.
PPM has more than 1,600 MW of operating assets currently under its ownership or control and, of that, PPM has full economic interest in 1,368 MW, see Table 7 (page 31). The majority of PPM’s capacity, 606 MW of wind power contracted for a period of 25 years and 237 MW of thermal power contracted for a period of 30 years, comes from long-term agreements while 525 MW comes from outright ownership of six wind plants and two thermal plants. PPM’s windfarms are on land owned or leased for 25 years or more. PPM also owns major gas storage facilities in Alberta, Canada and in Katy, Texas representing a total of 44 BCF of gas storage capacity.
UK Businesses The UK properties consist of generating stations, transmission and distribution facilities and certain non-operational properties in which the company holds freehold or leasehold interests.
ScottishPower owns seven power stations in Scotland, five of which are operational and two in England. It also owns three windfarms in Northern Ireland, six in Scotland, and one in the Republic of Ireland. In addition, the company has joint venture interests in one power station in England and three windfarms, two of which are in England and one in Wales. All generation plant is owned by the group, with the exception of the non-operational Methil power station, which is held on a ground lease that expires in 2012, and the windfarms which are generally held on ground leases of at least 25 years’ duration. See Table 8 (page 32) for further details of operational generation assets.
At 31 March 2004, the UK transmission facilities included approximately 4,000 circuit km of overhead lines and underground cable operated at 400 kV, 275 kV and 132 kV. In addition, the distribution facilities included over 110,000 circuit km of overhead lines and underground cable at voltages operating from 33 kV to 0.23 kV. The group holds either permanent rights or way leaves which entitle it to run these lines and cables through private land. See Table 9 (page 32) for further details.
10 Description of Legislative and Regulatory Background
As a public limited company (“plc”), Scottish Power plc is subject to the UK Companies Acts and is also registered as a holding company under the US federal Public Utility Holding Company Act of 1935, which is administered by the US federal Securities and Exchange Commission (“SEC”). Hence, Scottish Power plc, PacifiCorp and other subsidiaries are subject to regulation unless specific subsidiaries or transactions are otherwise exempt by SEC rules or orders. SPUK and its subsidiaries are exempt because SPUK is an exempt foreign utility as defined in the 1935 Act. Whereas US federal and state regulatory commissions generally have jurisdiction over mergers, acquisitions and the sale of utility assets, the UK Government, as a way to maintain control over ScottishPower and certain of its subsidiaries, required at privatisation the issuance of a ScottishPower “Special Share”. The Special Share only affected corporate control transactions at the overall group holding company level and had no effect on PacifiCorp. On 5 May 2004, the UK Government announced the redemption of the Special Share, following a review which concluded that public policy objectives are now adequately protected by the legal and regulatory framework currently in place.
ScottishPower’s UK operations are subject to such EU Directives as the UK Government brings into effect, specifically, the EU energy liberalisation directives and EU prohibitions on anti-competitive agreements and the abuse of a dominant position (implemented through the Competition Act 1998, which came into effect from 1 March 2000) and also to the provisions of the Utilities Act 2000 (“Utilities Act”). The Utilities Act introduced a legal framework for energy company licences based on standard, UK-wide conditions and, taken together with requirements of the Department of Trade and Industry (“DTI”) and licence changes introduced by the Regulators, defines the regulatory framework within which SPUK and its subsidiaries must operate.
A summary of the more specific legislative and regulatory background to the operations of the group’s businesses is set out below.
PacifiCorp is subject to the jurisdiction of the public utility regulatory authorities in each of the states in which it conducts retail electricity operations. These authorities regulate various matters including prices, services, accounting, issuance of securities and other matters. PacifiCorp is a “licensee” and a “public utility” as those terms are used in the Federal Power Act (“FPA”) and is, therefore, subject to regulation by the Federal Energy Regulatory Commission (“FERC”) as to accounting policies and practices, certain prices and other matters.
Because PPM does not conduct retail electricity operations, it is not subject to the same state public utility commission regulation as PacifiCorp. However, certain of its wholesale activities are regulated by the FERC and the state commissions impose certain limitations on affiliate transactions. In addition, PPM’s gas storage activities in Texas are subject to regulation by the FERC and the Texas Railroad Commission and those in Canada by the Alberta Energy and Utilities Board.
FERC Issues
California refund case PacifiCorp is one of a number of parties to a FERC investigation of potential refunds for energy transactions in California during past periods of high-energy prices and, in 2001/02, established a provision of $17.7 million for these potential refunds. PacifiCorp’s ultimate exposure to refunds is dependent upon any final order issued by the FERC in this proceeding.
ScottishPower Annual Report and Accounts 2003/04 17
Business Review Description of Legislative and Regulatory Background
FERC show-cause orders In August 2003, PacifiCorp and the FERC staff reached a resolution on the FERC order to show why various parties’ behaviour during the California energy crisis did not constitute manipulation of the wholesale electricity market. Under the terms of the settlement agreement, PacifiCorp denied liability and agreed to pay a nominal amount of $67,745 in exchange for complete and total resolution of the issues raised relating to it in the FERC’s show-cause order. The FERC issued its final order approving the settlement in March 2004. Several market participants have requested a rehearing of the FERC’s approval and a decision on a rehearing is expected from the FERC during the summer of 2004. In January 2004, the FERC dismissed PPM from the show-cause proceedings, finding that PPM did not engage in prohibited practices during the relevant period and indicating in the motion to dismiss several reasons why PPM’s behaviour did not constitute manipulation of the wholesale electricity market.
Northwest refund case In June 2003, the FERC terminated its proceeding in this case, concluding that ordering refunds would not be an appropriate resolution of the issues relating to wholesale spot-market bilateral sales in the Pacific Northwest between 25 December 2000 and 20 June 2001. In November 2003, the FERC issued its final order denying a requested rehearing. Several market participants have filed petitions in the court of appeals for review of the FERC’s final order.
Federal Power Act Section 206 case In November 2003, the FERC also issued its final order denying a rehearing of PacifiCorp’s request for recovery of excessive prices charged under certain wholesale electricity purchases scheduled for delivery during summer 2002. Appeals for review of the FERC’s final order by PacifiCorp and Morgan Stanley Capital Group, Inc. were transferred to the D.C. Circuit Court of Appeals for consolidation in December 2003. PacifiCorp obtained dismissal of the Morgan Stanley appeal, and requested transfer of the case back to the US Court of Appeals for the Ninth Circuit.
FERC market-based rates In February 2004, PPM’s Katy Storage and Transportation business unit was granted market-based rate-making authority subject to re-examination if there is a significant change to Katy’s market power status.
Multi-State Process (“MSP”)
PacifiCorp is involved in a collaborative process with stakeholders in the six states it serves to develop mutually acceptable solutions to the issues faced by PacifiCorp and the states as a result of the operations of a multi-state utility. MSP seeks to clarify roles and responsibilities, including cost allocations for future generation resources, to provide states with the ability independently to implement state energy policy objectives and to achieve a permanent consensus on each state’s responsibility for the costs and entitlement to the benefits of PacifiCorp’s existing assets. Between April 2002 and July 2003, PacifiCorp and key parties from the states it serves (or, in the case of California, a key monitoring contact) analysed over 50 options which were narrowed to two possibilities. Following the July 2003 meeting, PacifiCorp undertook extensive analytical work to develop a single proposal that would best balance its needs and the requirements of the states in addressing the positions, issues and concerns raised and discussed during the course of the collaborative and individual state meetings. This work culminated in a regulatory filing in September 2003 in the states of Utah, Oregon, Wyoming and Idaho. A similar filing was made in Washington in December 2003 as part of the general rate case filing. A filing in California will follow, coordinated with rate case activity. Utah, Oregon and Wyoming continued formal and informal meetings among the states and commissions over the months to May 2004. Direct and rebuttal testimony is expected to be filed over May and June 2004, with hearings scheduled for July 2004. In Washington, hearings are scheduled for August/September 2004 with a probable order date of mid-November 2004.
Regional Transmission Organization (“RTO”)
PacifiCorp, in conjunction with nine other utilities, is seeking to form a Regional Transmission Organization (“RTO”), now to be known as Grid West, in response to the FERC’s Order 2000. Creation of the RTO is subject to regulatory approvals from the FERC and state regulatory commissions. In September 2002, the FERC found that, with some modification and further development of certain details, the RTO proposal satisfies the 12 characteristics and functions in the FERC’s Order 2000. Concerns raised by regional stakeholders about the RTO proposal have resulted in a renewed regional process to develop a staged approach to RTO formation that provides for enhanced regional input and accountability. The RTO, if and when fully implemented, would serve as an independent transmission provider for the RTO region and have the operational authority needed to direct bulk wholesale electricity transfers over a majority of the 60,000 miles of transmission lines owned by its members. Under the current proposal the RTO would have operational control but PacifiCorp would continue to own its transmission assets.
In July 2002, the FERC issued a Notice of Proposed Rulemaking, proposing a new Standard Market Design for wholesale electricity markets. The FERC subsequently issued a “Wholesale Power Market Platform” white paper in April 2003, which signalled a greater willingness to defer to regional solutions and not adopt overly prescriptive rules. After the Standard Market Design white paper was released, the Grid West filing utilities, operating through the Regional Representatives Group, a formal regional stakeholder body, developed a consensus of regional issues and opportunities and
18 ScottishPower Annual Report and Accounts 2003/04
unanimously approved a proposal for future progress. The Regional Representatives Group is currently developing an implementation plan for this regional proposal, which includes timing for seating an independent Board of Trustees, obtaining the necessary regulatory approvals and the first phase of operation by an independent regional operator. PacifiCorp expects that, in its final rule, the FERC will allow implementation schedules to vary depending on local needs and will allow for local differences. The FERC is closely monitoring any pending legislation in the US Congress and has not yet set a date for issuing the final rule.
Relicensing of Hydroelectric Projects
PacifiCorp’s hydroelectric portfolio consists of 54 plants with a net plant capability of 1,164 MW, about 15% of PacifiCorp’s total generating capacity. The majority of the hydroelectric generating portfolio is operated under licences from the FERC, granted for periods of 30 to 50 years. There is a complex regulatory process to apply for licence renewal which begins five and a half years before the expiration of an existing licence and involves a number of federal and state agencies, Native American tribes, as well as other stakeholders. Some state and federal agencies have mandatory authority to require certain terms and conditions to be included in the FERC licence. Often existing licences expire prior to the FERC’s issuing of a new licence. In these cases, the FERC has historically issued annual operating licences so that the project can continue to operate while alternatives are evaluated; the FERC is continuing this practice.
In order to facilitate the licensing process, PacifiCorp may agree to early implementation of expected licence conditions, or settlement terms, if a settlement has been reached with licensing stakeholders. The cost of these measures, together with the costs for hydroelectric relicensing, are expected to be included in rates and, as such, not to have a material adverse impact on the group’s consolidated results of operations. During calendar year 2003, PacifiCorp filed general rate cases in Utah, Oregon, Wyoming and Washington, which included each state’s portion of the relicensing process costs associated with the projects where new licenses have become effective or are close to being issued by the FERC. In Oregon and Utah, the general rate cases ended in a commission approved settlement, and the commissions did not contest the hydroelectric relicensing costs. In Wyoming, the commission’s general rate case order did not challenge the hydroelectric relicensing costs included in the test year, whilst, in Washington, the recovery of relicensing costs is among the issues being considered in the current rate case, which is expected to conclude by November 2004.
Regulatory Established Returns
The regulatory commissions in the various states where PacifiCorp operates approve an appropriate level of cost recovery for debt, preferred equity and common equity which results in an allowed return on rate base costs (“ROR”), including an allowed return on equity (“ROE”) representing the return on shareholder investment. Determination of these returns, and the composition of the investment costs included in the rate base, is made by the commissions in hearings on general rate cases. Rates are then set to allow PacifiCorp the opportunity, with no guarantees, to meet its expenses, recover its investments and earn the allowed ROE for its shareholders. PacifiCorp is currently pursuing a regulatory programme in all states, with the objective of keeping rates closely aligned to ongoing costs. In recently completed general rate cases, regulators in Utah, Oregon and Wyoming allowed full cost recovery on new investments for growth. This includes recovery of the investment costs themselves through inclusion in regulatory rate base, as well as recovery of operation and maintenance expenses. In addition, PacifiCorp is requesting similar cost recovery and rate base treatment of growth investments in a general rate case now in process in Washington and will include recent investments for growth in regulatory rate base calculations for future general rate cases in Idaho and California.
Commissions in all states served by PacifiCorp monitor PacifiCorp’s achieved ROE for appropriateness in current market conditions. PacifiCorp continues to refine its internal procedures and to work with the commissions to ensure that all prudently incurred costs are reflected in its rates and that actual rates achieve allowable ROE levels. General rate adjustments reflecting changes in the regulated cost base granted in Utah, Oregon, Wyoming and California during 2003/04 have an annualised value of almost $100 million. In addition, PacifiCorp has a general rate case pending in Washington seeking approximately $27 million of proposed annual price increases to recover system investments and rising costs, including insurance, pension, healthcare, power, infrastructure and security costs. The Washington case should be completed by November 2004. Further rounds of rate cases are under consideration or development in most of the states served by PacifiCorp. As with any general rate case, the outcome of these requests is uncertain.
Recovery of Excess Power Costs
PacifiCorp has made progress towards recovering the deferred power costs incurred during the period of extreme volatility and unprecedented high price levels beginning in the summer of 2000 and extending through the summer of 2001. The Utah portion of these costs has been recovered through rate orders amounting to $147 million and recovery continues of $131 million plus ongoing carrying charges in Oregon and $25 million in Idaho. The Oregon rate order is the subject of an appeal by intervening parties which, if successful following oral arguments in May 2004, could require some refunds. In Wyoming, PacifiCorp’s request for deferred power cost recovery was denied, a decision which has now been appealed to the Wyoming Supreme Court. On 30 April 2004, PacifiCorp filed another challenge to the decision in the US District Court for Wyoming, requesting recovery of over $150 million for wholesale power and transmission costs previously denied by
ScottishPower Annual Report and Accounts 2003/04 19
Business Review Description of Legislative and Regulatory Background
the Wyoming Public Service Commission (“WPSC”). In Washington, PacifiCorp filed for deferral and recovery of excess net power costs estimated at the time to be $17.5 million, including carrying charges, or, alternatively, that it be allowed to file a general rate case, which would otherwise not have been allowed until December 2005. The decision of the Washington Utilities and Transportation Commission (“WUTC”) was not to allow for the deferral and recovery of excess power costs but to allow PacifiCorp to file a general rate case any time before July 2005 that addresses the level of prices needed to cover all ongoing costs to serve Washington customers. This decision was challenged in August 2003 by the Public Counsel section of the state attorney general’s office. A status conference was held in November and PacifiCorp and the WUTC staff submitted a joint reply brief in April 2004. In May 2004, the court confirmed the WUTC decision. Notwithstanding the pending challenge, PacifiCorp filed its Washington general rate case in December 2003 and expects that a final order will be made in November 2004.
Under UK Generally Accepted Accounting Principles (“GAAP”), all PacifiCorp’s net power costs are charged to the profit and loss account when incurred. There is, therefore, a time lag between the recognition of allowable excess power costs under UK GAAP compared to US GAAP, which continues to benefit future UK GAAP reported earnings.
Demand Side Management (“DSM”)
PacifiCorp continues to offer its Energy Exchange programme in Utah, Oregon, Wyoming, Washington and Idaho. This programme is an optional, supplemental service, which allows participating customers an opportunity voluntarily to reduce electricity usage in exchange for a payment at times and prices determined by PacifiCorp. The programme is designed to enable all customers of one MW and greater to help address periods of high wholesale prices and peaks in demand when they occur.
During the summer of 2003, PacifiCorp filed and received regulatory approval in Utah for three new residential DSM programmes: a refrigerator recycling programme, an air-conditioning load control programme and an incentive programme to encourage the installation of evaporative coolers or energy-efficient air-conditioners. PacifiCorp filed for a tariff rider to allow it to recover costs incurred through the implementation of all DSM programmes approved by the Utah Public Service Commission (“UPSC”). Following the filing of testimony, tariff proposals and a series of technical conferences, interested parties have approved a stipulation detailing the introduction of a tariff rider mechanism and a self-direction programme for large customers. This stipulation was heard and approved by the UPSC in September 2003 and, following discussions with regulatory parties, PacifiCorp proposed setting an initial collection rate of 3% for the DSM tariff rider. The 3% collection rate, approximately $28 million annually, was approved by the UPSC in March 2004 and became effective, as planned, on customer bills from 1 April 2004.
PacifiCorp also completed DSM services in Oregon under a transition agreement with the Energy Trust of Oregon (“ETO”) helping to ensure that customers’ efficiency needs were adequately served throughout the ETO’s initial start-up period and development of utility replacement programmes. The ETO was established as the deliverer of DSM services to Oregon as part of the State’s industry restructuring legislation that was implemented in March 2002. Under a recovery method similar to Utah’s tariff rider mechanism, PacifiCorp continues to invest in DSM in Washington State at around 3% of retail revenues.
In addition to its supply side Requests for Proposal, under the IRP, PacifiCorp issued a separate RFP for the demand side resources called for in the IRP in June 2003. Analysis of initial responses has been completed and PacifiCorp has selected certain proposals for further evaluation.
Renewable Energy
The 2003 IRP found that 1,400 MW of renewable energy was cost-effective over the following 10 years. PacifiCorp executed a power-purchase agreement with a new, 41 MW windfarm in Milton-Freewater, Oregon, in conjunction with the ETO. The ETO uses funds collected under Oregon’s “public benefits charge” to cover the above-market cost of the wind project while PacifiCorp purchases the power at market price. This was the first joint effort on renewable energy development between PacifiCorp and the ETO, which is to exist through to 2012. PacifiCorp also released an RFP for 1,100 MW of renewable generation over a seven-year period and will evaluate bids during 2004/05.
During 2003/04 there were several policy developments affecting renewable generation. California continued to clarify implementation rules on its renewable portfolio requirement, which calls for investor-owned utilities in the state to supply 20% of their California-based load from renewables in 2017 and encourages publicly-owned utilities to do the same. Utilities such as San Diego Gas and Electric and Sacramento Municipal Utility District have begun to invest in new renewable projects. PacifiCorp is waiting for the disposition of clarifying legislation pending in the California General Assembly before implementing a compliance strategy. The Washington legislature contemplated a renewable portfolio standard in the 2004 legislative session but the measure failed to pass out of the House. The Utah legislature passed a sales and use tax exemption for renewable energy equipment in 2004 to create an incentive for renewable development within the state.
In 2003/04, PacifiCorp’s “Blue Sky” programme, which offers customers the opportunity to support renewable energy development above its system investments, was approved by the California Public Utilities Commission (“CPUC”) and the Idaho Public Utility Commission (“IPUC”). The programme is now available to all customers in PacifiCorp’s service territory. Based on data compiled by the US Department of Energy, PacifiCorp ranks fifth nationwide in customer participation and fourth in MWh sales in voluntary renewable energy programmes.
20 ScottishPower Annual Report and Accounts 2003/04
Competition and Deregulation
During 2003/04, PacifiCorp continued to operate its electricity distribution and retail business under state regulation. Certain industrial customers in Oregon can choose alternative electricity suppliers and the California General Assembly is debating legislation to restore direct access options for large customers. However, deregulation of the retail market has not developed widely and, whilst customer demand for choice in each state may eventually lead to retail competition in some form, no significant proposals for customer choice were brought forward in any of the legislatures outside California during 2003/04. PacifiCorp currently owns and operates transmission facilities as part of its vertically integrated operations. Transmission costs are bundled with generation and distribution costs in approved retail rates. Rules issued by the FERC in 1996 designed to facilitate competition in the wholesale market on a nationwide basis give greater flexibility and more choices to wholesale electricity customers. The moves to introduce RTOs also impact on PacifiCorp’s transmission responsibilities and, possibly, the resultant revenues.
A summary of the outcomes and significant further regulatory and legislative developments in the states concerned is set out below.
Utah
PacifiCorp commenced a general rate case in May 2003. In January 2004, the UPSC approved a stipulation allowing an annual increase of $65 million, representing a 7% average price increase. The increase in customer rates was effective on 1 April 2004. A stipulation on rate spread and rate design was filed with, and approved by, the UPSC in January 2004. This order establishes rates giving PacifiCorp the opportunity to collect the previously ordered 7% average price increase and earn an authorised ROE of 10.7%.
Oregon
In August 2003, the Oregon Public Utility Commission (“OPUC”) approved a settlement of PacifiCorp’s general rate case filed in March 2003. Under the settlement, base rates increased by $8.5 million annually on 1 September 2003, resulting in a 1.1% average price increase and an effective authorised ROE of 10.7% based on the filed capital structure. Also, a $12 million merger credit for the period from January 2004 to December 2004 was eliminated and a further merger credit will be reduced from $6 million to $4 million and amortised to return the full amount to customers by December 2004.
Wyoming
In May 2003, PacifiCorp filed a general rate case with the WPSC to recover rising costs (including insurance premiums, pension funding and healthcare costs) and request an increase in the authorised ROE to 11.5%. Hearings in the case were completed in January 2004 and an order granting a $22.9 million annual increase (and authorising a 10.75% ROE) was issued in March 2004. The new rates took effect in early March 2004. In September 2003, PacifiCorp filed a request to establish a power cost adjustment mechanism (the “PCAM”). This mechanism was intended to protect PacifiCorp from net power cost volatility and reduce the regulatory lag associated with recovery of net power costs, which are defined as fuel and wheeling expenses and wholesale sales and purchases. Hearings in the PCAM case were held in March 2004. The request to establish the PCAM was denied in April 2004.
Washington
In October 2003, PacifiCorp filed petitions with the WUTC for accounting orders to allow deferral and amortisation of the Trail Mountain coal mine closure costs and environmental remediation costs and requesting WUTC authorisation of accounting treatment relating to pension liability as well as confirmation by the WUTC that certain actuarially determined pension costs are recoverable in rates. These filings were made in response to the stipulation approved in the last general rate proceeding in Washington requiring that items treated as regulatory assets under authorisations from other states, which are proposed for inclusion in Washington at the end of the rate plan period, be supported by accounting authorisations in Washington. In December 2003, PacifiCorp filed with the WUTC for a general rate increase of $26.7 million annually, or 13.5% to recover higher power costs; increases in insurance, pension, healthcare, infrastructure and security costs; increase authorised ROE to 11.25% and receive approval for the proposed inter-jurisdictional cost allocation protocol. In addition, PacifiCorp is requesting that the WUTC adopt the findings of a prudence review of generating resources acquired since the 1986 Washington general rate case. The WUTC has adopted a procedural schedule requiring testimony from the staff and other parties in June 2004 and PacifiCorp’s rebuttal testimony in July 2004. Hearings are scheduled to begin on 30 August 2004 with a final order expected in November 2004.
Idaho
In August 2003, the IPUC approved as filed PacifiCorp’s July 2003 application for approval of a renewable-energy tariff. Under the proposed tariff, residential and non-residential customers can purchase newly developed wind, geothermal and solar powered energy in fixed increments. In December 2003 PacifiCorp filed with the IPUC to recover $4.2 million related to Idaho’s portion of income tax payments resulting from audits of prior years. A stipulated agreement between the parties was filed in mid-May 2004. The filing requests recovery over 16 months, beginning in June 2004, when a power cost recovery surcharge, which began in June 2002, expires.
California
The CPUC issued a final order in November 2003 approving two stipulations in the general rate case and finalising permanent rates. The order grants an additional annual increase of $2.8
ScottishPower Annual Report and Accounts 2003/04 21
Business Review Description of Legislative and Regulatory Background
million effective from 1 December 2003. Combining this order with the interim increase in June 2002 results in an overall annual price increase of $7.6 million. This represents a 13.6% average price increase, with an authorised ROE of 10.9%.
13 Regulation of the Electricity and Gas Industries in the UK
The UK electricity and gas industries are regulated under the provisions of the Electricity Act, the Gas Acts and the Utilities Act. The Electricity and Gas Acts provided for the privatisation and restructuring of the industries in the late 1980s and the 1990s, including the introduction of price regulation for electricity transmission and distribution and gas transportation; and of competition in electricity generation, gas storage and the supply of both gas and electricity. The Acts established the licensing of industry participants and created regulatory bodies for each of the electricity and gas industries. In 2000, the Utilities Act enabled the electricity and gas regulators to be merged as the Authority, established new independent consumer councils and provided powers for Government Ministers to give statutory guidance on social and environmental issues and to set energy efficiency targets and renewables obligations.
The Utilities Act transferred the functions of the previous electricity and gas industry regulators to the Authority and provided for the appointment of a Chairman and other members of the Authority by the Secretary of State for Trade and Industry (“Secretary of State”). The Chairman of the Authority holds office for renewable periods of five years and is the Managing Director of Ofgem which provides administrative support to the Authority. Under the Utilities Act, the principal objective of the Secretary of State and the Authority is to protect the interest of customers, wherever appropriate by promoting effective competition. In carrying out those functions, they are required to have regard to the need to secure that all reasonable demands for electricity and gas are met; the need to ensure that licence holders are able to finance their functions; the interests of individuals who are disabled or chronically sick, of pensionable age, with low incomes or residing in rural areas. The Authority exercises, concurrently with the Director General of Fair Trading, certain functions relating to monopoly situations under the Fair Trading Act 1973 and the Enterprise Act 2002 and to anti-competitive conduct under the Competition Act 1980 and the Competition Act 1998. The Authority also manages UK compliance with the European Community Liberalisation Directive, which is concerned to introduce competition in generation and supply and non-discriminatory access to gas transportation and electricity transmission and distribution across the EU.
The Licensing Regime
The Authority is responsible for granting new licences or licence extensions for each of the following separate activities:
Electricity generation – the production of electricity at power stations, hydroelectric plants, windfarms and some industrial plants. Through its wholly-owned subsidiary, ScottishPower Generation Limited, the group is licensed to operate some 5,400 MW of generating capacity and, by contracting in the wholesale market, has access to capacity operated by other licensed generators.
Electricity transmission – the bulk transfer of electricity across a high-voltage network of overhead lines, underground cables and associated equipment typically operating at or above 132 kV. Through its wholly-owned subsidiary, SP Transmission Limited, the group owns and is licensed to operate the transmission system in central and southern Scotland. ScottishPower’s transmission system is connected to that of SSE in the north of Scotland and is linked to the National Grid in England & Wales and to the Northern Ireland transmission system by interconnectors which enable the export and import of electricity within the UK. Following a review by the Authority, a parliamentary bill has been published to facilitate revised arrangements in respect of the interconnector between Scotland and England; these are now expected to be in place by 2005.
Electricity distribution – the transfer of electricity from the high voltage transmission system and its delivery to customers, across a network of overhead lines and underground cables operating at voltages ranging from 33 kV to 0.23 kV. The Utilities Act required separate licensing of the 14 regional distribution businesses introduced under electricity privatisation. Each Public Electricity Distributor (“PED”) licensee is required, among other duties, to develop and maintain an efficient, coordinated and economical system of electricity distribution and to offer terms for connection to, and use of, its distribution system on a non-discriminatory basis, in order to ensure competition in the supply and generation of electricity. Through its wholly-owned subsidiaries, SP Distribution Limited and SP Manweb plc, the group is licensed to distribute electricity within its two distribution services areas for all suppliers whose customers are within the areas. Charges for distribution are made to the various suppliers as appropriate. The Authority has granted a derogation, which will lapse only in certain limited circumstances, allowing the distribution businesses in the ScottishPower and Manweb PED licence areas to be managed and operated jointly.
Gas transportation and storage – the onshore transportation system, most of which is owned and operated by Transco, the transportation arm of National Grid Transco plc, and the rest by other gas transporters, conveys gas from the beach terminals to consumers and is interconnected with the gas transportation systems of continental Europe, Northern Ireland and the Republic of Ireland. Storage capacities are largely used to balance supply and demand over time. Major facilities are used to balance seasonal variations in demand while diurnal storage
22 ScottishPower Annual Report and Accounts 2003/04
capacities provide flexibility in meeting changing gas demand on a daily basis. Competition in storage has been introduced progressively since 1998 through the auction of major storage capacity owned by Transco and the provision of new capacity by independent operators, including ScottishPower. Through its wholly-owned subsidiary, SP Gas Limited, the group is licensed as a gas transporter.
Gas shipping – gas shippers contract with gas transporters to have gas transported between the beach terminal and the point of supply. Gas shippers can also access storage facilities. The group is licensed as a gas shipper.
Supply of gas and electricity – the bulk purchase of gas and electricity by suppliers and its sale to customers, with the associated customer service activities, including customer registration, meter reading, sales and marketing, billing and revenue collection. Large industrial and commercial customers have been able to choose their energy suppliers for a number of years and the residential market was opened to competition progressively, commencing in April 1996, with residual controls on residential electricity prices ending in March 2002. Any electricity supplier wishing to supply electricity to domestic customers must obtain authorisation from the Authority and be subject to additional domestic supply obligations in its licence, including having its codes of practice (statements of intent about how the supplier will interact with customers) approved by the Authority. Broadly comparable arrangements allow British Gas Trading to supply mains gas to any connected customer in competition with licensed gas suppliers. Customers may continue to take supplies from the pre-privatisation monopoly supplier for the area or may choose an alternative licensed supplier. Once customers have changed a gas or electricity supplier, they are able to change supplier again subject to the contractual terms offered by licensed suppliers and approved by the Authority. Through its wholly owned subsidiary, ScottishPower Energy Retail Limited, the group is licensed as a gas supplier and an electricity supplier.
Modification of licences The Authority is responsible for monitoring compliance with the conditions of licences and, where necessary, enforcing them through procedures laid down in the Electricity and Gas Acts. Under these Acts, as amended by the Utilities Act, licences consist of standard licence conditions, which apply to all classes of licences, and special conditions particular to that licence. The Authority may modify standard licence conditions collectively through making proposals to all relevant licence holders. If some licence holders object, the modification may be carried out only if the number of objectors is below a specified minority. The Authority may modify a special licence condition with the agreement of the licence holder after due notice, public consultation and consideration of any representations or objections. In the absence of agreement for a special licence condition or if objections are above the specified minority threshold for a standard licence condition, the only means by which the Authority can secure a modification is following a modification reference to the Competition Commission and in the circumstances set out below. A modification reference requires the Competition Commission to investigate (having regard to the matters in relation to which duties are imposed on the Secretary of State and the Authority) and report on whether matters specified in the reference in pursuance of a licence operate, or may be expected to operate, against the public interest; and, if so, whether the adverse public interest effect of these factors could be remedied or prevented by modification of the conditions of the licence. If the Competition Commission so concludes, the Authority must then make such modifications to the licence as appear to it requisite for the purpose of remedying or preventing the adverse effects specified in the report, after giving due notice and consideration to any representations and objections. The Secretary of State has the power to veto any modification.
Modifications to licence conditions may also be made in consequence of a reference under the Fair Trading Act 1973, the Enterprise Act 2002 or the Competition Act. ScottishPower’s acquisition of Manweb in 1995 and its merger with PacifiCorp in 1999 both involved ScottishPower’s giving of undertakings to the Secretary of State to agree to modifications to the licences under which the group operates in the UK. Broadly, these modifications were designed to ring-fence various UK regulated businesses, to require that the group had sufficient management and financial resources to fulfil its UK obligations and to ensure that UK regulators would continue to have access to the information needed to carry out their duties.
Term and revocation of licences Licences under the Electricity Act, as modified by the Utilities Act, may be terminated by not less than 25 years’ notice given by the Secretary of State and may be revoked in certain circumstances specified in the licence. These include the insolvency of the licensee, the licensee’s failure to comply with an enforcement order made by the Authority and the licensee’s failure to carry on the activities authorised by the licence.
Price Controls
It is recognised that the development of competitive markets is not appropriate in some areas: particularly in the core activities of transmission and distribution of electricity and the operation of the gas transportation system. In these areas, regulatory controls are deemed necessary to protect customers in monopoly markets (by determining inflation-limited price caps) and to encourage efficiency. The group’s UK transmission and distribution businesses are subject to price controls (or revenue controls in the case of the transmission business) which restrict the average amount, or total amount, charged for a bundle of services. The price caps are expressed in terms of an “RPI – X” constraint on charges, where “RPI” represents the annual percentage change in the UK’s retail price index, and X is a
ScottishPower Annual Report and Accounts 2003/04 23
Business Review Description of Legislative and Regulatory Background
percentage determined by the Authority. The X factor is used to reflect expected efficiency gains and investment requirements. For example, where RPI is running at 3% and X is 2%, a company would be able to increase the average charge for a bundle of services by 1% per annum. The Authority from time to time reviews the price cap formulae. Through participation in, and the submission of evidence to, these price control reviews and, where necessary, through the Competition Commission modification process described above, companies have the opportunity to comment on and seek to influence the final outcome of any price control review.
Transmission price control The revised transmission price control for ScottishPower took effect for the five years from 1 April 2000. The BETTA review proposes a Great Britain-wide wholesale market for electricity and revised arrangements. BETTA is dependent upon primary legislation and is expected to be implemented in 2005. Ofgem has proposed a two-year roll-forward of the current price control for SP Transmission from April 2005.
Distribution price control The maximum distribution revenue is calculated from a formula that is based on customer numbers as well as units distributed. Distribution price controls for the ScottishPower and Manweb areas, which took effect for the five years from 1 April 2000, are currently subject to a review by the Authority aimed at ensuring that customers’ interests are protected and that companies have the appropriate incentives to invest and operate efficiently. Key challenges for this review include modifying the regulatory framework to provide incentives for distribution companies to connect distributed generation and developing the quality of supply incentives established at the previous review.
Throughout its operations, ScottishPower will meet, or better, relevant legislative and regulatory environmental requirements and codes of practice. ScottishPower will publish its 2003/04 Environmental and Social Impact Report and Environmental Performance Report in October 2004. Copies will be available on request from the Company Secretary and the reports will be available on the ScottishPower website.
US Environmental Regulation
Federal, state and local authorities regulate many of PacifiCorp’s activities pursuant to laws designed to restore, protect and enhance the quality of the environment. These laws have increased the cost of providing electricity service and give rise to identifiable contingencies, principally in respect of Clean Air Act matters, which are subjects of discussions with the US Environmental Protection Agency (“EPA”) and state regulatory authorities. PacifiCorp expects that future costs relating to these matters may be significant and consist primarily of capital expenditure. PacifiCorp expects to manage its decision making and implementation of these matters effectively so that these and future costs will be found to be prudent and recoverable in rates and, as such, not to have a material adverse impact on the group’s consolidated results of operations.
Air Quality
PacifiCorp’s fossil fuel-fired electricity generation plants are subject to regulation under federal, state and local requirements. PacifiCorp uses emission controls, low-sulphur coal, plant operating practices sensitive to environmental impacts and continuous emissions monitoring to enable its plants to comply with emission and opacity limits, visibility and other air quality requirements. The EPA has initiated a regional haze programme intended to improve visibility at specific federally protected areas, some of which are located near PacifiCorp plants. PacifiCorp is anticipating climate change challenges with additions of renewable generation, conservation and thermal resources as outlined in the IRP. Carbon dioxide (“CO2”) emissions risk has been recognised in PacifiCorp’s IRP through the use of a projected additional cost based on the fuel’s carbon content when evaluating the cost of new resources. PacifiCorp also supports development of trading and other market mechanisms, as well as offset strategies, where feasible, to reduce future compliance costs to customers.
The US Congress is currently considering several proposed bills that would create enforceable limits on electricity plant emission of sulphur dioxide (“SO2”), oxides of nitrogen (“NOx”), mercury and in some cases CO2. The EPA also has proposed new regulations that could impact emissions and is pursuing enforcement actions against selected coal-fired power plants in the eastern and mid-western US with the aim of causing nationwide emission reductions. All of these efforts may lead to additional control equipment being installed over the next 10-15 years. PacifiCorp expects that future costs relating to these matters may be significant and would consist primarily of capital expenditure but will be spread over a number of years. PacifiCorp also expects that the impact will be mitigated by recovery through regulatory ratemaking.
Endangered Species
Protection of threatened and endangered species and their habitat makes it difficult and more costly to perform some of the core activities of PacifiCorp, including the siting, construction, maintenance and operation of new and existing transmission and distribution facilities, as well as hydroelectric, thermal and wind generation plants. In addition, endangered species issues impact the relicensing of existing hydroelectric generating projects, generally raising the price PacifiCorp pays to purchase wholesale electricity from hydroelectric facilities owned by others and increasing the costs of operation of PacifiCorp’s own hydroelectric resources. Nonetheless, PacifiCorp creates and implements management systems to ensure that environmental considerations are successfully incorporated into major business decisions relating to its generation, transmission and distribution assets.
24 ScottishPower Annual Report and Accounts 2003/04
Environmental Clean-ups
Under the federal Comprehensive Environmental Response, Compensation and Liability Act and similar state statutes, entities that accidentally or intentionally disposed of, or arranged for the disposal of, hazardous materials may be liable for clean-up of the contaminated property. In addition, the current or former owners or operators of affected sites also may be liable. PacifiCorp has been identified as a potentially responsible party in connection with a number of clean-up sites because of current or past ownership or operation of the property or because PacifiCorp sent materials deemed to be hazardous to the property in the past. PacifiCorp has completed several clean-up actions and is actively participating in investigations and remedial actions at other sites. The costs associated with those actions are not expected to be material to the group’s consolidated results of operations or financial position.
Mining
The federal Surface Mining and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during the operation and upon completion of mining activities. These obligations stipulate that mine property be restored consistent with specific standards and the approved reclamation plan. Significant expenditures are expected to be required as individual PacifiCorp mining operations are closed and reclamation occurs. The costs associated with reclamation are subject to the regulatory process. PacifiCorp expects to be allowed to recover these costs.
Water Quality
The federal Clean Water Act and individual state clean water regulations require a permit for the discharge of wastewater, including storm water runoff from the electricity plants and coal storage areas, into surface waters and groundwater. PacifiCorp believes that it has management systems in place to monitor performance, identify problems and take action to assure compliance with permit requirements.
UK Environmental Regulation
The group’s UK businesses are subject to numerous regulatory requirements with respect to the protection of the environment, including environmental laws which regulate the construction, operation and decommissioning of power stations, pursuant to legislation implementing environmental directives adopted by the EU and protocols agreed under the auspices of international bodies such as the United Nations Economic Commission for Europe (“UNECE”). The group believes that it has taken and continues to take measures to comply with applicable laws and regulations for the protection of the environment. Applicable regulations and requirements pertaining to the environment change frequently, however, with the result that continued compliance may require material investments, or that the group’s costs and results of operation are less favourable than anticipated.
Electricity Generation, Transmission, Distribution and Supply
The Electricity Act obligates the Secretary of State to take into account the effect of electricity generation, transmission, distribution and supply activities upon the physical environment in approving applications for the construction of generating facilities and the location of overhead power lines. The Electricity Act requires the group to take into account the conservation of natural features of beauty and other items of particular interest and, in terms of the Environmental Impact Assessment Regulations, to carry out an environmental assessment when it intends to construct significant overhead transmission systems or power stations of greater capacity than 50 MW. The group also prepares formal statements on the “Preservation of Amenity and Fisheries” in line with the requirements of the Electricity Act.
The Utilities Act provided for environmental guidance to be given by the Secretary of State to the energy regulator, Ofgem, and for regulations to be drawn up which require licensed electricity suppliers to secure a certain percentage of their supplies from renewable energy sources, compliance being demonstrated by tradable “Renewables Obligation Certificates”. The current objective is that 10% of UK energy should come from renewable sources by 2010 and an objective of 20% by 2020 was included in the UK Government White Paper on energy. ScottishPower continues to develop its windfarm business and expects to meet the company target of 10% generation from renewables by 2010. In December 2003, the UK Government announced its desire to increase the firm Renewables Obligation target to 15% by 2015. The Utilities Act also provided for energy efficiency targets to be set for licensed suppliers to be implemented by an “Energy Efficiency Commitment”. The emphasis on energy saving has remained in the recent UK publication: Energy Efficiency – the Government’s Plan for Action. This was announced in April 2004 and indicated an increase in current Energy Efficiency Commitment targets for the period between 2005 and 2011.
The Environmental Protection Act of 1990 (“EPA 1990”) requires that potentially polluting activities such as the operation of combustion processes (which includes power plant) requires prior authorisation. The Act also provides for the licensing of waste management and imposes certain obligations and duties on companies which produce, handle, and dispose of waste. Waste generated as a result of the group’s electricity activities is managed to ensure compliance with legislation and waste minimisation is undertaken where possible.
Generation Activities
The principal emissions from fossil-fuelled electricity generation are SO2, NOx, CO2 and particulate matter, such as dust, with the main waste being ash, namely pulverised fuel ash and furnace bottom ash. The primary focus of current environmental legislation to date has been to reduce emissions of SO2, NOx and particulates, the first two of which contribute to acid rain. More recently, the UK Government has consulted on the EU
ScottishPower Annual Report and Accounts 2003/04 25
Business Review Description of Legislative and Regulatory Background
Emissions Trading Scheme which will regulate the release of CO2 from fossil-fuelled power stations. The proposed arrangements in the UK will be subject to approval by the EC during 2004, with scheme implementation scheduled for January 2005. A number of other power station emissions and discharges are subject to environmental regulation.
EPA 1990 is the primary UK statute governing the environmental regulation of power stations. In April 1991, it introduced a system of Integrated Pollution Control (“IPC”) for large scale industrial processes, including power stations, now enforced with respect to emissions to atmosphere in England & Wales by the Environment Agency (“EA”) and in Scotland by the Scottish Environment Protection Agency (“SEPA”). Each of ScottishPower’s power stations is required to have its own IPC authorisation, issued by the EA or SEPA, regulating emissions of certain pollutants, seeking to minimise pollution of the environment and containing an improvement programme. Each IPC authorisation requires that a power station uses the Best Available Techniques Not Entailing Excessive Cost (“BATNEEC”) to prevent the emissions described above or, to the extent this is not practicable, to minimise and render harmless any such emissions. ScottishPower’s IPC authorisations do not have an expiry date, but the EA or SEPA is required to review the conditions contained within them at least once every four years and may impose new conditions to prevent or reduce emissions of pollutants, subject to the application of BATNEEC.
The EU has agreed a Directive on Integrated Pollution Prevention and Control, which introduces a system of licensing for industrial processes such as power stations. This Directive is being implemented via the Pollution Prevention and Control Regulations (“PPC Regulations”) which will bring modifications to the IPC regime into effect, on a staged basis. The EU Directive will eventually require that all emission and pollution control measures are placed onto a “Best Available Techniques” basis to control the impact on the environment.
The EU has adopted a framework directive on ambient air quality assessment and management and, under the auspices of UNECE, protocols regarding reductions in the emissions of SO2 and NOx have been agreed. These protocols are currently implemented in the EU by means of the Large Combustion Plants Directive (“LCPD”). The EU has finalised a “Ceilings Directive” which will implement the SO2 and NOx targets agreed in the UNECE Gothenburg Protocol. In the UK, the Government has submitted details to the EC of how it proposes to implement the LCPD. Continued uncertainty remains on final arrangements surrounding implementation of bulk emissions and emission limit values. Compliance with local air quality issues will continue to be implemented in the UK by means of the National Air Quality Strategy (“NAQS”) published in 1997, and reviewed in 2000. The provisions of the LCPD and of NAQS are to be introduced through the PPC permitting process on a plant-by-plant basis.
The group has identified options that, given the appropriate commercial conditions, would enable it to continue the environmental improvements required by potential future limits arising from this review, without materially constraining operational and commercial flexibility. In particular, gas-reburn technology, as used at Longannet, offers greater potential to reduce emissions than other technology in use elsewhere in the UK.
The Waste Incineration Directive (“WID”) imposes emission limits on the incineration or co-incineration of materials deemed to be “waste” in terms of relevant EU legislation. These will also be implemented via the PPC permitting process. During 2003/04, SEPA indicated that it considers that the WID provisions will apply to the burning of sewage sludge pellets used at Longannet Power Station. ScottishPower Generation Limited has petitioned for a Judicial Review of this decision by SEPA.
Contaminated Sites
While the nature of developments in environmental regulation and control cannot be predicted, the group anticipates that the direction of future changes will be towards tightening controls. In view of the age and history of many sites owned by the group, the group may incur liability in respect of sites which are found to be contaminated, together with increased costs of managing or cleaning up such sites. Site values could be affected and potential liability and clean-up costs may make disposal of potentially contaminated sites more difficult. The Contaminated Land Regulations, which implement provisions of the Environment Act 1995 (“EA1995”), require local authorities to identify sites where significant harm is being caused and to take appropriate steps. In order for harm to be demonstrated it must be shown that a source of pollution, a receptor and a pathway are present. Harm may be eliminated by clean-up or by breaking the source to receptor pathway. Clean-up is only required to “fit for subsequent use” standards, so that environmental compliance is consistent with the intended use of the site.
Other proposals which may, under certain conditions impose strict liability for environmental damage, such as the Environmental Liability Directive, are presently being adopted by the EC. ScottishPower is not currently aware of any liability which it may have under EA1995 or proposed EU directives which will have a materially adverse impact on its operations.
Numerous laws and related codes of practice –international, EU, UK and US – ensure that companies offer equal opportunities to all individuals, regardless of gender, race, disability and age. Similarly, both the US and the UK have extensive legislation covering health and safety at work. ScottishPower has well-defined policies in place throughout its businesses to ensure that there are equal opportunities in employment and to comply with applicable employment laws. These policies cover a range of specific issues, such as disciplinary and grievance procedures, equal pay, harassment, race, sex and other forms of discrimination, stress and non-retaliation for the reporting of compliance issues.
26 ScottishPower Annual Report and Accounts 2003/04
A more extensive description of how the businesses discharge their wider responsibilities to protect the welfare, health and safety of the public and their employees, can be found in the ScottishPower Environmental and Social Impact Report and the ScottishPower Workplace Performance Report, available on the ScottishPower website. A brief overview of the two most extensively regulated aspects of employee relations follows.
Equal Opportunity
US businesses In the US, equal employment opportunities are provided without regard to race, colour, sex, religion, creed, age, sexual orientation, national origin, veteran’s status, physical or mental disability or any other status protected under applicable local, state or federal law. The group provides equal opportunity for qualified applicants and employees and maintains a programme of affirmative action, pursuant to legal requirements, in order effectively to employ minorities and women and to encourage workforce diversity. The programme also covers disabled persons and veterans. The US affirmative action programmes establish specific, results-oriented procedures; determine whether effective utilisation of minorities and women is achieved; incorporate equal employment principles in supervisory training; and promote effective community outreach efforts for women and minority applicants.
UK Businesses The UK businesses work with both outside organisations and an internal equality forum to consider policies for racial equality, family issues, disabled people and other key areas. ScottishPower is affiliated with a number of organisations including the Equal Opportunities Commission, Employer’s Forum on Age, Employer’s Forum on Disability, Commission for Racial Equality and Parents at Work. Internal human resources staffs work with these organisations to find ways to incorporate their expertise into group and business unit policies.
The introduction of The Employment Equality Regulations 2003 extended existing equality legislation to protect workers from discrimination on the basis of their sexual orientation, religion or similar belief. The UK businesses have reviewed and updated their existing equality policies to ensure that they meet the new requirements. They have also worked in conjunction with their recognised trade unions to jointly develop and implement a new UK-wide Company Agreement. The agreement harmonises a number of significant terms and conditions, including maternity and paternity leave provisions and also contains harmonised employment procedures dealing with discipline, sickness absence, performance and grievance.
Health and Safety
Assessments against the Group Health & Safety Standards were carried out during November/December 2003, establishing a baseline for business unit performance against the Standards and the creation of a ScottishPower Best Practice Model. Targets have been set for business units to improve performance against the Standards and to improve in key areas. These are included in the business unit scorecards. Progress against the Standards will be measured in the fourth quarter of 2004/05.
US Businesses The lost time accident (“LTA”) rate for the US businesses reduced from 0.90 to 0.63, a reduction in LTAs of 55 to 42 during 2003/04. The PacifiCorp Employee Climate Survey scores also showed a good safety culture in place across PacifiCorp. At PPM, Pacific Klamath Energy received its Oregon Sharp Certification from the Oregon Occupational Safety and Health Administration, distinguishing its safety programme with other state leaders. In public safety, the amount of electricity public safety education performed increased about 20% above prior years, and the programme was ranked in the top tier in the industry. A team from Energy West Mining also won the National Mine Rescue Competition.
The group’s US Health & Safety Committee continues to meet on a regular basis, providing senior executive oversight and leadership in PacifiCorp and PPM in these areas. Major initiatives are underway in PacifiCorp’s power delivery, generation and mining business units and in PPM to reduce and prevent accidents.
The US businesses participate with other industry stakeholders in the regulatory process on significant safety and health regulatory proposals affecting the utility and mining industries. PacifiCorp is also well represented amongst these stakeholders, with safety professionals occupying leadership positions in both mining and electricity trade associations safety groups.
UK Businesses The LTA rate for the UK businesses reduced from 0.83 to 0.62, a reduction in LTAs of 60 to 48. The highlight of the year was in the generation business which had a period of seven months without any LTAs.
To recognise the importance of employee involvement ScottishPower, in partnership with its trade unions, launched the new “Safety Representatives’ Charter” (“the Charter”) during August 2003. ScottishPower and the trade unions are committed to achieving a long-term goal of operating without harm to employees, customers and the public. Collaboration, over many years, in the company’s health and safety activities has resulted in improved performance, particularly over recent years when the incidence of accidents and ill-health in the workplace has seen a consistent decline. Safety representatives have contributed greatly to improved performance and the introduction of the Charter will allow them to make a greater contribution in the future.
In the UK, the Reporting of Injuries, Diseases and Dangerous Occurrences Regulations set out the requirements for reporting of all work-related accidents. As UK regulators and enforcement authorities increasingly seek to raise the priority and importance that companies give to health and safety issues, they are likely to take action for any non-compliance. The
ScottishPower Annual Report and Accounts 2003/04 27
Business Review Description of Legislative and Regulatory Background
company continues to support industry organisations, such as the Association of Electricity Producers, Engineering Employers Federation and Energy Networks Association, and engages in representation to the UK Health and Safety Executive, the DTI and other relevant organisations through these industry groups.
The risk management process established by the group is designed to identify, assess, monitor and manage each of the various types of risk involved in the group’s business and activities; measure quantitative market risk exposure; and identify qualitative market risk exposure in its business. Increases or reductions in future retail demand for electricity as a result of economic growth or downturns, among other factors, including abnormal weather, may impact retail revenues, cash flows and investment levels. In particular, the pace of economic recovery in PacifiCorp’s service territories, for example, Oregon which has been experiencing recessionary conditions, could impact PacifiCorp’s results and timing of investments. The principal discussion of the group’s management of market risks is set out on pages 49 to 54. An outline of the approach taken to the management of other business risks is set out in the following paragraphs.
Operating Risk
Operating risk is the risk that assets and mechanical systems, as well as business processes and procedures, might not perform as expected, with the result that the group may be unable to meet a portion of its obligations without resorting to an unanticipated market transaction. Operating risk is primarily mitigated through a combination of sound maintenance practices, prudent and safe operational processes and insurance products, such as business interruption insurance.
Security Risk
The emergence of terrorist threats, both domestic and foreign, is a continued risk to the entire utility industry, including ScottishPower. Potential destruction of assets and disruptions to operations are not readily determinable. The group has identified critical assets and developed several levels of security and emergency response to meet the increased threat level. The US businesses are well advanced in the implementation of a physical security plan to enhance the security surrounding critical assets under the overall auspices of the North American Electric Reliability Council 1200 Urgent Action standard.
The impact of cyber attacks has been relatively small, as compared to most businesses, based on preventive measures taken and rapid response to events. Planning and prioritisation for additional security enhancements is underway for 2004/05. In the UK, there is an established liaison with the security services and police, to ensure that critical assets are protected against potential threat of terrorism.
Pension Risk
As a result of the relative decline in the equity markets and low interest rates, the group anticipates that pension expense and cash contributions into the pension schemes will increase in the near future. The investment risk has been addressed as part of the pensions review undertaken by both the group and its pension scheme trustees, focusing on the asset allocation of the schemes.
Regulatory Risk
In the US the group is subject to the jurisdiction of federal and state regulatory authorities. The FERC establishes tariffs under which PacifiCorp provides wheeling services to the wholesale market and the retail market for states allowing retail competition, establishes both cost-based and market-based tariffs under which PacifiCorp sells electricity at wholesale and has licensing authority over most of PacifiCorp’s hydroelectric generation facilities. The utility regulatory commissions in each state independently determine the rates PacifiCorp may charge its retail customers in that state.
Each state’s rate setting process is based upon that commission’s acceptance of an allocated share of total PacifiCorp costs as its “responsibility”. When different states adopt different methods to address this “inter-jurisdictional cost allocation” issue, some costs may not be incorporated into any rates in any state. Rate making is done on the basis of “normalised” costs, so if in a specific year, realised costs are higher than normal, rates will not be high enough to cover those costs. Likewise, if in a given year costs are lower than normal or revenues are higher, PacifiCorp retains the resulting higher-than-normal profit. Each commission sets rates based on a “test year” of its choosing. In states that use a historical test year, rate adjustments can follow cost increases, or decreases, by up to two years. Regulatory lag results in a delay in recovery of costs currently incurred but not in rates, and also imposes a time-value-of-money burden on PacifiCorp. Further, each commission decides what levels of expense and investment are “necessary, reasonable and prudent” in providing service. In the event that a commission decides that part of PacifiCorp’s costs do not meet this standard, such costs will be “disallowed” and not recovered in rates. For these reasons, the rates authorised by the regulators may be less than the costs to PacifiCorp to provide electricity service to its customers in a given period.
Several of PacifiCorp’s hydroelectric projects are in some stage of the FERC relicensing under the FPA. The relicensing process is a political and public regulatory process that involves sensitive resource issues. PacifiCorp is unable to predict the requirements that may be imposed during the relicensing process, the economic impact of those requirements, whether new licences will ultimately be issued or whether PacifiCorp will be willing to meet the relicensing requirements to continue operating its hydroelectric projects.
Federal, state and local authorities regulate many of PacifiCorp’s activities pursuant to laws designed to restore,
28 ScottishPower Annual Report and Accounts 2003/04
protect and enhance the quality of the environment. PacifiCorp is unable to predict what material impact, if any, future changes in environmental laws and regulations may have on the group’s consolidated results or financial position.
In the UK, the electricity and gas industries are regulated primarily through powers assigned, under the Utilities Act 2000, to the Authority which licenses industry participants, enforces licence conditions, regulates quality of service and sets pricing formulae for electricity transmission and distribution activities. In principle, it has wide discretion in the exercise of its obligation to act to protect the interests of customers, wherever appropriate by promoting effective competition, whilst the need to ensure that licence holders are able to finance their functions is only one of a number of other factors to which the Authority must have regard. However, the Authority operates through a process of extensive consultation and on pre-determined timetables, making its activities relatively predictable. Regulations designed to restore, protect and enhance the quality of the environment are similarly introduced through a process of intensive – and generally EU-wide – consultation with the industry and other parties. Nonetheless, there is a general tightening of environmental regulation and it must be recognised that the future impact of the costs of such requirements cannot be forecast with precision.
Political Risk
In the US, PacifiCorp and PPM conduct business in conformance with a multitude of federal and state laws. At present the US Congress is considering significant changes in energy, air quality and tax policy. However this energy legislation has been stalled short of a final vote. If a comprehensive energy bill is enacted, the law is likely to include direction for the regulation of, as well as financial incentives to invest in, electricity transmission. The law would make changes to improve the hydroelectric relicensing process and would extend and modify terms of the recently-expired renewable energy production tax credit. Extension of the credit generally would be likely to benefit PacifiCorp’s efforts to develop, acquire and maintain a low-cost generation portfolio and PPM’s efforts to continue developing its renewable energy portfolio. Extension of the renewable energy tax credit is generally well supported and may pass in other legislation if a comprehensive energy bill fails. Timing is uncertain, however. Changes to the Clean Air Act contemplated by a variety of pending legislative proposals are being monitored closely in that they may impact requirements for emissions from fossil-fuelled generation plants. No action was taken on President Bush’s Clear Skies Act or on competing proposals in calendar year 2003 and enactment of new clean air legislation is not considered likely in calendar year 2004. As the Clear Skies legislation has not progressed in the US Congress, the EPA is considering new regulations governing power plant emissions.
The laws of the states in which PacifiCorp operates affect PacifiCorp’s generation, transmission and distribution business. All state legislatures in those states except California have completed their calendar year 2004 general sessions. The Oregon Legislature may convene in special session during calendar year 2004 to consider tax reform proposals. The Utah Legislature referred for study during 2004 Senate Bill 198 which would affect rules for procurement of new electricity resources.
In the UK an Energy Bill was introduced to Parliament in November 2003 with provisions for implementing the Government’s policies in relation to the nuclear industry, renewable energy and energy trading markets including the implementation of BETTA. Government energy policy was set out in a White Paper in February 2003 emphasising a continuing intention to make maximum use of market-based mechanisms whilst seeking to reduce the use of carbon, boost energy-saving and maintain efforts to mitigate the impact of fuel costs on lower-income households. There is particular emphasis on the use of renewable energy sources and developing discussion of the network enhancements likely to be required for the increased use of both renewables and embedded generation. This policy framework offers opportunities for the group and has shaped a number of current business plans. The White Paper, and the proposed provisions of the Energy Bill, have received broad endorsement across the UK political spectrum and appear to be largely consistent with EU policy generally. However, as the policy outlined extends well into the future, it could be subject to change and amendment by future Governments.
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 and certain of the Klamath Tribes’ members. 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. The claim seeks in excess of $1.0 billion in damages. PacifiCorp believes it has a number of defences and intends to vigorously defend any claim of liability for the matters alleged by the Klamath Tribes.
Other than the foregoing, ScottishPower is not aware of any material pending legal proceedings, other than ordinary routine litigation incidental to the business of the group, to which ScottishPower or any of its subsidiaries is a party, or any such proceedings known to be contemplated by any governmental authority.
ScottishPower Annual Report and Accounts 2003/04 29
Business Review Summary of Key Operating Statistics
18 Summary of Key Operating Statistics
Table 1 - Summary of PacifiCorp Generating Facilities as at 31 March 2004
| Location |
Energy source |
Installation dates |
Nameplate rating (MW) |
Plant net capability (MW) |
||||||||
| Hydroelectric plants |
||||||||||||
| Swift |
Cougar, Washington | Lewis River | 1958 | 240.0 | 264.0 | |||||||
| Merwin |
Ariel, Washington | Lewis River | 1932-1958 | 135.0 | 144.0 | |||||||
| Yale |
Amboy, Washington | Lewis River | 1953 | 134.0 | 165.0 | |||||||
| Five North Umpqua Plants |
Toketee Falls, Oregon | N. Umpqua River | 1949-1956 | 133.3 | 139.0 | |||||||
| John C. Boyle |
Keno, Oregon | Klamath River | 1958 | 80.0 | 90.0 | |||||||
| Copco 1 and 2 |
Hornbrook, California | Klamath River | 1918-1925 | 47.0 | 54.5 | |||||||
| Clearwater 1 and 2 |
Toketee Falls, Oregon | Clearwater River | 1953 | 41.0 | 41.0 | |||||||
| Grace |
Grace, Idaho | Bear River | 1908-1923 | 33.0 | 33.0 | |||||||
| Prospect 2 |
Prospect, Oregon | Rogue River | 1928 | 32.0 | 36.0 | |||||||
| Cutler |
Collingston, Utah | Bear River | 1927 | 30.0 | 29.1 | |||||||
| Oneida |
Preston, Idaho | Bear River | 1915-1920 | 30.0 | 28.0 | |||||||
| Iron Gate |
Hornbrook, California | Klamath River | 1962 | 18.0 | 20.0 | |||||||
| Soda |
Soda Springs, Idaho | Bear River | 1924 | 14.0 | 14.0 | |||||||
| Fish Creek |
Toketee Falls, Oregon | Fish Creek | 1952 | 11.0 | 12.0 | |||||||
| 34 Minor Hydroelectric Plants |
Various | Various | 1895-1990 | 99.0 | * | 94.4 | * | |||||
| Subtotal (54 hydroelectric plants) |
1,077.3 | 1,164.0 | ||||||||||
| Thermal electric plants |
||||||||||||
| Jim Bridger |
Rock Springs, Wyoming | Coal-Fired | 1974-1979 | 1,541.1 | * | 1,413.4 | * | |||||
| Huntington |
Huntington, Utah | Coal-Fired | 1974-1977 | 996.0 | 895.0 | |||||||
| Dave Johnston |
Glenrock, Wyoming | Coal-Fired | 1959-1972 | 816.7 | 762.0 | |||||||
| Naughton |
Kemmerer, Wyoming | Coal-Fired | 1963-1971 | 707.2 | 700.0 | |||||||
| Hunter 1 and 2 |
Castle Dale, Utah | Coal-Fired | 1978-1980 | 728.0 | * | 662.0 | * | |||||
| Hunter 3 |
Castle Dale, Utah | Coal-Fired | 1983 | 495.6 | 460.0 | |||||||
| Cholla Unit 4 |
Joseph City, Arizona | Coal-Fired | 1981 | 414.0 | * | 380.0 | * | |||||
| Wyodak |
Gillette, Wyoming | Coal-Fired | 1978 | 289.6 | * | 268.0 | * | |||||
| Carbon |
Castle Gate, Utah | Coal-Fired | 1954-1957 | 188.6 | 175.0 | |||||||
| Craig 1 and 2 |
Craig, Colorado | Coal-Fired | 1979-1980 | 172.1 | * | 165.0 | * | |||||
| Colstrip 3 and 4 |
Colstrip, Montana | Coal-Fired | 1984-1986 | 155.6 | * | 149.0 | * | |||||
| Hayden 1 and 2 |
Hayden, Colorado | Coal-Fired | 1965-1976 | 81.3 | * | 78.0 | * | |||||
| Blundell |
Milford, Utah | Geothermal | 1984 | 26.0 | 23.0 | |||||||
| Gadsby Steam |
Salt Lake City, Utah | Gas-Fired | 1951-1952 | 251.6 | 235.0 | |||||||
| Gadsby Peakers |
Salt Lake City, Utah | Gas-Fired | 2002 | 141.0 | 114.0 | |||||||
| Little Mountain |
Ogden, Utah | Gas-Fired | 1972 | 16.0 | 14.0 | |||||||
| Hermiston |
Hermiston, Oregon | Gas-Fired | 1996 | 237.0 | * | 245.0 | * | |||||
| Camas Co-Gen |
Camas, Washington | Black Liquor | 1996 | 52.2 | 52.0 | |||||||
| Subtotal (16 thermal electric plants) |
7,309.6 | 6,790.4 | ||||||||||
| Other plants |
||||||||||||
| Foote Creek |
Arlington, Wyoming | Wind Turbines | 1998 | 32.6 | * | 32.6 | * | |||||
| Subtotal (1 other plant) |
32.6 | 32.6 | ||||||||||
| Total generating facilities (71) |
8,419.5 | 7,987.0 | ||||||||||
Notes:
| * | Jointly owned plants; amount shown represents PacifiCorp’s share only. |
Hydroelectric project locations are stated by locality and river watershed.
Table 2 – PacifiCorp Recoverable Coal Reserves as at 31 March 2004
| Location |
Notes |
Plant served |
Recoverable tons (in millions) | |||
| Craig, Colorado |
1 | Craig | 48.8 | |||
| Emery County, Utah |
2 | Huntington and Hunter | 50.6 | |||
| Rock Springs, Wyoming |
3 | Jim Bridger | 120.7 | |||
Notes:
| 1 | These coal reserves are leased and mined by Trapper Mining, Inc., a Delaware non-stock corporation operated on a cooperative basis, in which PacifiCorp has an ownership interest of approximately 20%. |
| 2 | These coal reserves are mined by PacifiCorp subsidiaries. |
| 3 | These coal reserves are leased and mined by Bridger Coal Company, a joint venture between Pacific Minerals, Inc., a subsidiary of PacifiCorp, and a subsidiary of Idaho Power Company. Pacific Minerals, Inc. has a two-thirds interest in the joint venture. |
Coal reserve estimates are subject to adjustment as a result of the development of additional data, new mining technology and changes in regulation and economic factors affecting the use of such reserves.
30 ScottishPower Annual Report and Accounts 2003/04
Table 3 – PacifiCorp Electricity GWh Energy Sales by Customer Class
Electricity sales, by class of customer, for the years ended 31 March 2004, 2003, 2002 and 2001 were as follows:
| 2004 |
% |
2003 |
% |
2002 |
% |
2001 |
% | |||||||||
| Gigawatt hours sold |
||||||||||||||||
| – Residential |
14,460 | 21 | 13,287 | 17 | 13,395 | 19 | 13,455 | 18 | ||||||||
| – Commercial |
14,413 | 21 | 14,006 | 18 | 13,810 | 19 | 13,634 | 18 | ||||||||
| – Industrial |
19,133 | 27 | 19,048 | 25 | 19,611 | 27 | 20,659 | 27 | ||||||||
| – Government, Municipal and Other |
673 | 1 | 631 | 1 | 711 | 1 | 705 | 1 | ||||||||
| – Total Retail Sales |
48,679 | 70 | 46,972 | 61 | 47,527 | 66 | 48,453 | 64 | ||||||||
| – Wholesale Sales and Market Trading |
21,196 | 30 | 30,485 | 39 | 24,438 | 34 | 27,502 | 36 | ||||||||
| Total GWh Sold |
69,875 | 100 | 77,457 | 100 | 71,965 | 100 | 75,955 | 100 | ||||||||
Note:
The figures above are stated on a basis consistent with the reporting of sales in accordance with UK GAAP. Under US GAAP, following the implementation of Emerging Issues Task Force No. 03-11, ‘Reporting Gains and Losses on Derivative Instruments that Are Subject to Financial Accounting Standards Board Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes’ (“EITF 03-11”), certain transactions are no longer reported as Wholesale Sales and Market Trading. Wholesale Sales and Market Trading GWh volumes on a basis consistent with the reporting of sales in accordance with EITF 03-11 are: 13,407 for 2004; 14,873 for 2003; 13,403 for 2002 and 14,998 for 2001.
Table 4 – PacifiCorp Transmission and Distribution Systems Key Information 2003/04
| Pacific Power |
Utah Power |
Total | ||||
| Franchise area |
72,075 sq miles | 63,175 sq miles | 135,350 sq miles | |||
| System maximum demand |
4,190 MW | 4,732 MW | 8,922 MW | |||
| Transmission network (miles) |
||||||
| – Overhead |
15,763 | |||||
| Distribution network (miles) |
||||||
| – Underground |
5,393 | 8,321 | 13,714 | |||
| – Overhead |
26,118 | 17,632 | 43,750 | |||
Table 5 – Total Electricity Units Distributed in Pacific Power Service Area (GWh)
| Year |
Residential |
% |
Commercial |
% |
Industrial |
% |
Other |
% |
Total | |||||||||
| 1999/00 |
7,612 | 31 | 6,766 | 27 | 10,167 | 41 | 122 | — | 24,667 | |||||||||
| 2000/01 |
7,768 | 31 | 7,041 | 28 | 10,164 | 40 | 130 | 1 | 25,103 | |||||||||
| 2001/02 |
7,537 | 31 | 6,932 | 29 | 9,743 | 40 | 129 | — | 24,341 | |||||||||
| 2002/03 |
7,454 | 31 | 7,081 | 29 | 9,478 | 40 | 90 | — | 24,103 | |||||||||
| 2003/04 |
8,205 | 33 | 7,587 | 31 | 9,025 | 36 | 72 | — | 24,889 | |||||||||
Table 6 – Total Electricity Units Distributed in Utah Power Service Area (GWh)
| Year |
Residential |
% |
Commercial |
% |
Industrial |
% |
Other |
% |
Total | |||||||||
| 1999/00 |
5,416 | 24 | 6,061 | 27 | 10,302 | 46 | 541 | 2 | 22,320 | |||||||||
| 2000/01 |
5,687 | 24 | 6,593 | 28 | 10,495 | 45 | 575 | 2 | 23,350 | |||||||||
| 2001/02 |
5,858 | 25 | 6,878 | 30 | 9,868 | 43 | 582 | 2 | 23,186 | |||||||||
| 2002/03 |
5,833 | 26 | 6,925 | 30 | 9,570 | 42 | 541 | 2 | 22,869 | |||||||||
| 2003/04 |
6,256 | 26 | 6,826 | 29 | 10,109 | 42 | 599 | 3 | 23,790 | |||||||||
Table 7 – Summary of PPM Generating Facilities as at 31 March 2004
| Location |
Energy source |
Installation date |
Plant net capability (MW) | |||||
| Thermal electric plants |
||||||||
| Klamath Cogeneration Plant |
Klamath Falls, Oregon | Natural gas-fired - Combined cycle | 2001 | 506 | ||||
| West Valley Generating Plant |
West Valley City, Utah | Natural gas-fired - Single cycle | 2002 | 200 | ||||
| Klamath Generating Plant |
Klamath Falls, Oregon | Natural gas-fired - Single cycle | 2002 | 100 | ||||
| Sub-total (3 thermal electric plants) |
806 | |||||||
| Renewable electric plants |
||||||||
| Phoenix Wind Power Plant | Southern California | Wind generation | 1999 | 3 | ||||
| Stateline Wind Energy Center |
Oregon/ Washington | Wind generation | 2002 | 300 | ||||
| Klondike Wind Power Plant |
Northcentral, Oregon | Wind generation | 2001 | 24 | ||||
| High Winds Energy Center |
Northern California | Wind generation | 2003 | 162 | ||||
| Southwest Wyoming Wind Energy Center |
Southwest Wyoming | Wind generation | 2003 | 144 | ||||
| Moraine Wind Power Plant |
Southwest Minnesota | Wind generation | 2003 | 51 | ||||
| Flying Cloud Wind Power Plant |
Northwest Iowa | Wind generation | 2003 | 44 | ||||
| Mountain View III Wind Power Plant |
Southern California | Wind generation | 2003 | 22 | ||||
| Colorado Green Wind Power Plant* |
Southeast Colorado | Wind generation | 2003 | 81 | ||||
| Subtotal (9 renewable electric plants) |
831 | |||||||
| Total all plants (Owned or controlled plants) |
1,637 | |||||||
Note:
| * | Jointly owned plant |
ScottishPower Annual Report and Accounts 2003/04 31
Business Review Summary of Key Operating Statistics
Table 8 – Sources of ScottishPower Owned Generating Capacity and Output in the UK and the Republic of Ireland as at 31 March 2004
| Notes |
Number of generating sets and/or installed capacity (MW) |
Net output capacity (MW) |
Maximum capacity available (MW) | |||||
| Coal |
||||||||
| Longannet |
4 x 600 | 2,304 | ||||||
| Cockenzie |
4 x 300 | 1,152 | ||||||
| 1 | 3,456 | 2,880 | ||||||
| Gas Turbine |
||||||||
| Rye House |
1 x 715 | 715 | 715 | |||||
| Brighton |
2 | 1 x 414 | 400 | 200 | ||||
| Knapton |
1 x 42 | 42 | 42 | |||||
| Pumped Storage |
||||||||
| Cruachan |
4 x 100 | 400 | 400 | |||||
| Conventional Hydro |
||||||||
| Galloway Scheme |
109 | 106 | 106 | |||||
| Lanark Scheme |
17 | 17 | 17 | |||||
| Windfarms |
||||||||
| Beinn an Tuirc |
46 x 0.66 | 30 | 30 | |||||
| Barnesmore |
25 x 0.6 | 15 | 15 | |||||
| Hagshaw Hill |
26 x 0.6 | 16 | 16 | |||||
| P & L Windfarm |
3 | 103 x 0.3 | 31 | 15 | ||||
| Rigged Hill |
10 x 0.5 | 5 | 5 | |||||
| Corkey |
10 x 0.5 | 5 | 5 | |||||
| Elliots Hill |
10 x 0.5 | 5 | 5 | |||||
| Coal Clough |
4 | 24 x 0.4 | 10 | 4 | ||||
| Carland Cross |
4 | 15 x 0.4 | 6 | 3 | ||||
| Dun Law |
26 x 0.66 | 17 | 17 | |||||
| Hare Hill |
20 x 0.66 | 13 | 13 | |||||
| Cruach Mhor |
35 x 0.85 | 30 | 30 | |||||
| CHP |
102 | 102 | ||||||
| Total |
5,421 | 4,620 | ||||||
Notes:
| 1 | Scottish and Southern Energy was entitled to a supply of electricity from part of the capacity of ScottishPower’s coal-fired generating stations at Longannet and Cockenzie. This agreement terminated on 1 April 2004. |
| 2 | Brighton power station is owned by South Coast Power Limited, with ScottishPower Generation Limited and American Electric Power each having a 50% ownership interest. |
| 3 | The P & L Windfarm is owned by CeltPower Limited, with ScottishPower Generation Limited and Tomen Power (Europe) BV each having a 50% ownership interest. |
| 4 | The windfarms at Coal Clough and Carland Cross are owned by a joint venture between ScottishPower Generation Limited, Western Power Distribution and Renewable Energy Systems, with ScottishPower Generation Limited having a 45% ownership interest. |
Table 9 – UK Transmission and Distribution Systems Key Information 2003/04
| ScottishPower |
Manweb |
Total | ||||
| Franchise area |
22,950 km2 | 12,200 km2 | 35,150 km2 | |||
| System maximum demand |
4,227 MW | 3,136 MW |
7,363 MW | |||
| Transmission network (km) |
||||||
| – Underground |
218 | — | 218 | |||
| – Overhead |
3,738 | — | 3,738 | |||
| Distribution network (km) |
||||||
| – Underground |
41,137 | 25,754 | 66,891 | |||
| – Overhead |
24,457 | 20,205 | 44,662 | |||
Table 10 – Total Electricity Units Distributed in the ScottishPower Service Area (GWh)
| Year |
Residential |
% |
Business |
% |
Total | |||||
| 1999/00 |
8,385 | 38 | 13,996 | 62 | 22,381 | |||||
| 2000/01 |
8,505 | 38 | 14,189 | 62 | 22,694 | |||||
| 2001/02 |
8,698 | 39 | 13,864 | 61 | 22,562 | |||||
| 2002/03 |
8,643 | 39 | 13,689 | 61 | 22,332 | |||||
| 2003/04 |
8,620 | 39 | 13,639 | 61 | 22,259 | |||||
Table 11 – Total Electricity Units Distributed in the Manweb Service Area (GWh)
| Year |
Residential |
% |
Business |
% |
Total | |||||
| 1999/00 |
5,204 | 30 | 11,977 | 70 | 17,181 | |||||
| 2000/01 |
5,460 | 32 | 11,826 | 68 | 17,286 | |||||
| 2001/02 |
5,387 | 32 | 11,540 | 68 | 16,927 | |||||
| 2002/03 |
5,512 | 33 | 11,233 | 67 | 16,745 | |||||
| 2003/04 |
5,862 | 35 | 11,018 | 65 | 16,880 | |||||
32 ScottishPower Annual Report and Accounts 2003/04
This has been a year of strong financial performance for ScottishPower with increased operating profit and lower interest charges leading to higher pre-tax profit and earnings per share.
David Nish, Finance Director
ScottishPower Annual Report and Accounts 2003/04 33
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-recurring or non-operational in nature. In the years presented, these items are goodwill amortisation and exceptional items. Therefore, to provide more meaningful information, ScottishPower has focused its discussion of business performance on the results excluding goodwill amortisation and exceptional items. 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 discussed and reconciled to the non-GAAP figures. The full statutory results are presented in the “Group Profit and Loss Account” and in Note 1 “Segmental profit and loss information” on pages 90 and 91 and on pages 95 and 96 respectively. Within the following discussion, reference is made to a number of financial ratios, which management and external agencies use to assess the performance of our business, and would therefore be of interest to stakeholders. These ratios are not recognised GAAP measures and may not be comparable with similarly titled measures reported by other companies.
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 exceeding £1 billion. The group comprises four businesses operating in both a regulated and competitive environment in the UK and US, which serve over 5.8 million (2002/03: 5.2 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 accounted for 46% of group external turnover in the current year (2002/03: 53%), and 87% of operating profit (2002/03: 88%). The group’s geographical distribution of turnover and operating profit is broadly balanced between its UK and US operations.
The regulated businesses comprise PacifiCorp in the US and Infrastructure Division in the UK. Together they accounted for £2.7 billion of group turnover in the year, and almost £900 million of operating profit. 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. Together they contributed £3.1 billion of group turnover in the year, and over £130 million of operating profit. 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 4.2 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 around 1,600 MW of thermal and renewable generation under its ownership or control.
34 ScottishPower Annual Report and Accounts 2003/04
The businesses’ key drivers impacting the financial performance of the group are shown in Table 12. Other factors affecting our financial performance include increases and reductions in customer demand for electricity, economic growth and downturns and abnormal weather, all of which impact revenues, cash flows and investment. The group proactively manages its supply and demand balance, but any unanticipated changes in future customer demand, weather conditions, generation resource availability or commodity prices may affect revenues from and the cost of supplying power to customers.
ScottishPower’s strategic aim is to be a leading international energy company and underpinning this strategy is a commitment to deliver continued operational improvements, complemented by a balanced programme of investment for organic growth. In the year, we have succeeded in growing the operating profit of all of our businesses and have embarked on a significant investment programme, which is already delivering attractive returns throughout the group. These investments were assessed on a risk adjusted returns basis and were subject to a rigorous appraisal process. Our regulated businesses have delivered growth in the year with operating profit up by 7% on last year. This has been achieved through sustained investment and utilisation of our proven skills in operational, regulatory and asset management. Our competitive businesses have reported substantial improvements in operating profit up by 31% in the year. This is attributable to our ability to deploy our local market knowledge and skills, supplemented by our investment capabilities, into areas which deliver attractive returns and secure future growth opportunities.
ScottishPower is committed to maintaining an A– credit rating for its principal operating subsidiaries, which allows access to flexible borrowing sources at favourable cost. In addition to the cash generated from operations and existing cash resources, the group relies on the capital markets as a source of liquidity to fund investment as required.
The group seeks to minimise and manage earnings volatility whilst protecting the value of the group’s overseas assets through appropriate interest rate and foreign exchange risk management programmes. Against these objectives, the effective use of dollar denominated debt, derivatives and commodity price hedging have substantially protected the group’s earnings and net assets from foreign exchange volatility over the past 12 months, while allowing the group to benefit from interest rates in dollars that have been lower than those in sterling. In March 2004, the group repriced US$2,550 million of cross-currency swaps that act as overseas net investment hedges, resulting in a net cash receipt of £403 million, which has been used to reduce net debt. Substantially all of the group’s US investments continue to be protected from exchange rate movements, with US earnings similarly protected in the next financial year at an expected hedge rate in the range of approximately $1.50 – $1.55.
Table 12 – Key drivers
| PacifiCorp | Infrastructure Division | |
| • Achieving allowed regulatory rate of return on equity • Managing the regulatory rate case process |
• Maximising returns from investment in the regulatory asset base | |
| • Managing a balanced power position • Managing the impact of growing demand |
• Securing positive outcomes from the 2005 distribution and 2007 transmission price reviews | |
| • Improving operating and capital cost-efficiency |
• Improving operating and capital cost-efficiency | |
| PPM
• Availability of attractive business opportunities and favourable public policies
• Optimising returns from its gas and power portfolio by actively seeking to lock in value inherent in the portfolio’s assets and contracts |
UK Division
• Managing a balanced power position
• Continuing to grow the customer base at optimal tariff levels
• Further significant expansion of renewable generation at appropriate rates of return
• Improving operating and capital cost-efficiency |
ScottishPower Annual Report and Accounts 2003/04 35
Financial Review
During the year, earnings per share increased by 3.2 pence to 29.4 pence. Excluding goodwill amortisation, earnings per share increased by 8% to 36.4 pence, as a result of the businesses’ improved operational performance and lower group interest charges, offset in part by higher taxation charges. Key financial highlights are shown in the charts below.
Last year we announced our intention to target dividend cover based on full year earnings within a range of 1.5 to 2.0 times and ideally towards the middle of that range. This excludes goodwill amortisation and exceptional items. We have achieved that with our full year dividend of 20.50 pence per share, which is covered 1.78 times by earnings per share of 36.4 pence, excluding goodwill amortisation. Going forward, we are committed to grow dividends broadly in line with earnings. In the absence of unforeseen circumstances, ScottishPower intends to pay an identical dividend for each of the first three-quarters of 2004/05, of 4.95 pence per share per quarter. The balance of the total dividend for 2004/05 will be set in the fourth quarter.
3 Overview of the Year to March 2004
Group Profit and Loss
This has been a year of strong financial performance for ScottishPower with increased operating profit across all businesses and lower interest charges leading to higher pre-tax profit and earnings per share. Our policy to hedge dollar earnings to reduce the impact of currency volatility successfully mitigated the impact on earnings of the weaker US dollar.
Group turnover for the year to 31 March 2004 was £5,797 million, an increase of £523 million on the previous year, with the majority of the increase in the UK Division from balancing our electricity and gas positions, which was offset in cost of sales. The weaker US dollar reduced sterling revenues by £204 million. The translation effect of foreign exchange on earnings has been mitigated by our hedging strategy.
PacifiCorp’s turnover for the year was down by £181 million at £2,319 million mainly as a result of a £179 million adverse translation impact of the weaker US dollar. Dollar turnover in PacifiCorp was in line with last year as higher retail revenues from greater customer usage, favourable weather conditions and higher prices, were offset by lower wholesale volumes. Infrastructure Division’s turnover grew by £44 million to £358 million due to increased regulated income from higher sales to third party electricity suppliers and from increased new connection activities. The UK Division experienced turnover growth of 29%, with revenues rising by £630 million to £2,777 million mainly as a result of balancing activities in England & Wales and improved retail and wholesale gas revenues. PPM’s turnover improved by £57 million to £343 million, after a £25 million adverse US dollar translation impact, as a result of increased sales of natural gas, activities around storage assets, the addition of new wind generation and gas storage expansion.
There was no turnover from discontinued operations during the year, while last year’s results included turnover of £27 million generated in the period prior to the disposal of Southern Water, which was completed on 23 April 2002.
36 ScottishPower Annual Report and Accounts 2003/04
Cost of sales of £3,631 million increased by £404 million on last year, reflecting substantial growth in balancing our electricity and gas positions within the UK Division, offset in part by lower wholesale purchases in PacifiCorp and by the favourable US dollar translation impact. Transmission and distribution costs increased by £32 million to £545 million as a result of higher UK Division customer service support and credit management costs reflecting growth in customer numbers, and storm damage costs, higher depreciation and labour related costs in PacifiCorp, partly offset by the favourable US dollar translation impact. Administrative expenses (including goodwill amortisation) as shown in Table 13 were £12 million higher than last year at £626 million. Excluding goodwill amortisation, administrative expenses increased by £23 million due to increased energy efficiency and customer capture costs in the UK Division as a result of customer growth and increased costs in PPM to support business growth, partly offset by the favourable US dollar impact. Depreciation for continuing operations, which is included within each of the three preceding cost categories, was broadly in line with last year at £439 million. Increased levels of capital investment throughout the group have resulted in higher depreciation charges during the year, particularly in the US, however, the impact of the weaker dollar on translation has more than offset this.
| Table 13 – Administrative expenses (£m)
|
2003/04 |
2002/03 |
||||
| Administrative expenses |
626.2 | 614.5 | ||||
| Goodwill amortisation |
(128.0 | ) | (139.0 | ) | ||
| Administrative expenses excluding goodwill |
498.2 | 475.5 | ||||
As shown in Table 14 group operating profit improved significantly for the year, up £77 million (8%) to £1,023 million and, excluding goodwill amortisation, increased by £66 million to £1,151 million. Each of our four businesses delivered improved operating profit for the year. In particular, our competitive businesses, UK Division and PPM, produced strong performances with combined operating profit, excluding goodwill amortisation, up by over 29% on last year.
In PacifiCorp operating profit, excluding goodwill amortisation, increased by £23 million to £619 million, benefiting from strong retail revenue growth and the delivery of further operational cost efficiencies, partly offset by the impact of the weaker US dollar. Infrastructure Division’s operating profit showed an increase of £26 million (7%) to £394 million, primarily from higher regulated revenues and lower net operating costs. The UK Division’s operating profit, excluding goodwill amortisation, improved by £23 million to £101 million due to a combination of customer growth and prices resulting in improved electricity margins. In PPM, the benefit of our organic investment helped operating profit, excluding goodwill amortisation, grow by £8 million to £37 million.
| Table 14 – Group operating profit (£m)
|
2003/04 |
2002/03 | ||
| Operating profit |
1,022.6 | 945.9 | ||
| Goodwill amortisation |
128.0 | 139.0 | ||
| Operating profit excluding goodwill |
1,150.6 | 1,084.9 | ||
Operating profit in 2002/03 included £14 million from discontinued operations.
Goodwill amortisation of £128 million was £11 million lower than last year mainly as a result of the translation impact of the weaker US dollar reducing the goodwill charge for PacifiCorp.
The net interest charge reduced by £16 million to £238 million for the year, mainly attributable to the favourable exchange benefits from the weaker US dollar of £17 million, and also from lower interest rates in both the UK and US. The benefit to interest from our dollar balance sheet hedging strategy, whereby the group swaps out of sterling liabilities into dollar liabilities in order to hedge its US$ denominated net assets, was £39 million, £7 million lower than last year due to changes in the UK/US interest rate differential. Further discussion on interest charges is given within the Liquidity and Capital Resources section on page 46.
As shown in Table 15 profit before tax grew substantially in the year by £95 million (14%) to £792 million. Excluding goodwill amortisation, profit before tax improved by £84 million to £920 million with our continuing businesses delivering £95 million of the increase, offset in part by the contribution to last year’s profit before tax from discontinued operations of £11 million. The average US dollar to pound sterling exchange rate for the year for US profit before tax, excluding goodwill amortisation, and before the benefits of our hedging strategy, was $1.69. We sold forward our forecast dollar earnings at an average rate of $1.41 and this delivered an earnings hedging benefit compared to the average rate for the year of approximately £60 million. This has therefore protected group profit from the effect of the weaker US dollar, ensuring results were in line with our expectations. We expect our earnings for the financial year to March 2005 will continue to benefit from our hedging programme with an expected hedge rate in the range of approximately $1.50 – $1.55.
Table 15 – Profit before tax (£m)
| Continuing operations and Total 2003/04 |
Continuing operations 2002/03 |
Discontinued operations 2002/03 |
Total 2002/03 | |||||
| Profit before tax |
792.1 | 685.8 | 11.0 | 696.8 | ||||
| Goodwill amortisation |
128.0 | 139.0 | – | 139.0 | ||||
| Profit before tax excluding goodwill |
920.1 | 824.8 | 11.0 | 835.8 | ||||
The tax charge for the year increased by £39 million to £248 million, as a result of higher pre-tax profit in the current financial year and a higher effective rate of tax. As shown in Table 16, the effective rate of tax is calculated by dividing the tax charge by profit before tax, expressed as a percentage. For the year, the effective rate of tax was 31% compared to 30% for last year. Excluding goodwill amortisation, the effective rate of tax
ScottishPower Annual Report and Accounts 2003/04 37
Financial Review
was 27% compared to 25% for last year. The effective rate of tax is dependent on a number of factors. The mix of profits impacts the rate because of the higher rates applied to taxable profits in the US (around 38%) when compared to the UK (30%). An increase in the proportion of profits earned in the US, therefore, results in an increase in the group’s effective tax rate. The effective rate is lower than the statutory rate because the group seeks to carry out its commercial activities in a tax efficient manner and benefits from the group’s financing arrangements. Where the tax treatment of a specific item is debatable, the group makes realistic provision for the tax payable and will endeavour to negotiate a settlement with the tax authorities which is not less favourable than the accounting treatment of the item. As a result, when some of these items are agreed, the release of any balance of the provision will reduce the effective tax rate. In the current year, a lower value of provisions were released and, as a result, the effective tax rate has increased.
| Table 16 – Effective rate of tax (£m)
|
2003/04 |
2002/03 |
||||
| Tax charge |
248.4 | 209.0 | ||||
| Profit before tax |
792.1 | 696.8 | ||||
| Effective rate of tax |
31 | % | 30 | % | ||
| Profit before tax, excluding goodwill |
920.1 | 835.8 | ||||
| Effective rate of tax, excluding goodwill |
27 | % | 25 | % | ||
Profit after tax, as shown in Table 17, improved by £56 million to £544 million. Excluding goodwill amortisation, profit after tax grew by £45 million (7%) to £672 million, with our strong operating results and lower interest charges, being offset by higher tax charges.
| Table 17 – Profit after tax (£m)
|
2003/04 |
2002/03 | ||
| Profit after tax |
543.7 | 487.8 | ||
| Goodwill amortisation |
128.0 | 139.0 | ||
| Profit after tax excluding goodwill |
671.7 | 626.8 | ||
As a result of improved performance, earnings per share, as shown in Table 18, increased by 3.2 pence to 29.4 pence (12%) for the year. Excluding goodwill amortisation, earnings per share increased by 2.7 pence (8%) to 36.4 pence with the improvement comprising 3.1 pence from continuing operations, partly offset by 0.4 pence from discontinued operations reported last year.
| Table 18 – Earnings per share (pence)
|
Continuing operations and Total 2003/04 |
Continuing operations 2002/03 |
Discontinued operations 2002/03 |
Total 2002/03 | ||||
| Earnings per share (EPS) |
29.40 | 25.76 | 0.41 | 26.17 | ||||
| EPS impact of goodwill amortisation |
7.00 | 7.54 | – | 7.54 | ||||
| EPS excluding goodwill |
36.40 | 33.30 | 0.41 | 33.71 | ||||
The full year dividends were 20.50 pence per share and were covered 1.43 times by earnings per share of 29.4 pence. Excluding goodwill amortisation, dividend cover was 1.78 times.
Cash Flow and Net Debt
Cash flows from operating activities reduced by £49 million to £1,364 million for the year. In the year, favourable operating performance was partly offset by higher working capital commitments mainly due to increased gas stocks in PPM from growth in storage activities and higher debtors reflecting significant growth in our UK retail business. Interest, tax and dividend payments totalled £726 million. Net inflows from the sale of tangible fixed assets; fixed asset investments; and acquisitions and disposals, other than the £25 million Colorado Green joint venture, were £6 million. Financing net inflows, other than changes in net debt, were £459 million, mainly as a result of the cash receipt arising on the repricing of cross-currency swaps in March 2004 and the cancellation of cross-currency swaps earlier in the year. These cash flows combined, provided cash of £1,103 million which covered all of our £868 million net capital investment cash spend, and contributed to the reduction in net debt during the year. After the net benefit of £362 million arising from both the weaker US dollar and other non-cash movements, net debt was £3,725 million at 31 March 2004, £597 million lower than at 31 March 2003. Gearing (net debt/equity shareholders’ funds) was 79%, compared to 95% at 31 March 2003.
Investment
In the year, the group invested £901 million in its asset base. Of this £949 million related to fixed asset additions, and a further £25 million was invested in the Colorado Green joint venture, less both the £25 million increase in the reclamation provision for the Bridger coal mine and £48 million of capital grants and customer contributions. In the year, we invested in windfarm projects in the US and UK totalling more than 534 MW; commenced work on the new 525 MW Currant Creek natural gas-fired power plant in Utah; undertook substantial network investment in the US of 564 MVA and actively refurbished our network in the UK; and added to our gas storage capacity in the US.
Of the £901 million net investment in assets in the year, organic growth expenditure totalled £364 million, with 58% invested in our regulated businesses and 42% in our competitive businesses. Geographically, £268 million (74%) of growth spend was invested in the US and £96 million (26%) in the UK. The £537 million balance of refurbishment and upgrade spend was split £280 million in the US (52%) and £257 million in the UK (48%).
Our investment strategy is to drive the growth and development of our regulated and competitive businesses, through a balanced programme of capital investment, which will deliver returns ranging from allowed rates of return in our regulated businesses to higher returns in our competitive businesses. All investments are assessed on a risk adjusted returns basis, are expected to be earnings enhancing and should support our aim to retain our A– credit rating for our principal operating subsidiaries.
38 ScottishPower Annual Report and Accounts 2003/04
Our level of organic investment is expected to grow to approximately £1.2 billion next year, based on a US dollar/UK sterling exchange rate of approximately $1.80, enabling our businesses to optimise the performance of existing assets and pursue organic growth opportunities through a balanced programme of expenditure.
Business Reviews
PacifiCorp
PacifiCorp is our US regulated business and remains committed to delivering $1 billion EBIT (earnings before interest and tax, excluding goodwill amortisation) in 2004/05. The first quarter of 2004/05 has started less strongly than our expectations due to a combination of milder weather impacting on residential demand, lower hydro resource and lower thermal plant availability. PacifiCorp seeks to maximise its return on equity (“ROE”), which is a regulatory calculation, within the limits permitted by US state regulators. The outcome of general rate cases conducted by the state regulatory commissions sets the authorised ROE, with each commission establishing its own ROE for PacifiCorp. During the year, the authorised ROE specified by PacifiCorp’s state regulators ranged from 10.5% to 10.9%. Regulatory returns for PacifiCorp through the last reportable period (September 2003) were approximately 8%. Successful management of the regulatory rate process, maximising the returns on new investment and the recovery of costs through rate setting are key priorities for PacifiCorp to move towards achieving its allowed regulatory rate of return. PacifiCorp is currently pursuing a regulatory programme in all states in which it operates, with the objective of keeping rates closely aligned to ongoing costs and, in the year, has been awarded almost $100 million of additional annual revenue from rate cases. The key financial information is shown in Table 19.
Turnover in PacifiCorp reduced by £181 million to £2,319 million in the year, mainly because of the £179 million translation impact of the weaker US dollar. Excluding the effect of foreign exchange, residential, commercial and industrial revenue grew by £80 million in the year (6%), with volumes 4% higher. Residential and commercial revenues increased by £47 million (9%) and £17 million (4%) respectively, mainly as a result of higher customer usage, including the impact of a warmer summer and colder winter, favourable prices from rate case revenues and growth in average customer numbers up by 28,000 (2%) in total. Industrial revenues increased by £16 million, or 4%, primarily due to favourable price mix, resulting from different customer tariffs in the various states PacifiCorp serves, with average customer numbers remaining constant. Wholesale revenues fell by £87 million, mainly due to lower long-term and short-term sales volumes, partly offset by higher wholesale electricity prices of £34 million. Movements in wholesale revenues are largely offset by similar changes in cost of sales, resulting from the balancing of power positions. Other revenues fell by £29 million primarily due to the lower recovery of deferred power costs of £14 million.
In the year, operating profit increased by £34 million ($65 million) to £497 million ($736 million) and, excluding goodwill amortisation, by £23 million ($65 million) to £619 million ($943 million). The unfavourable impact of the weaker dollar on operating profit was £21 million, net of hedging benefits from the forward sale of dollars. PacifiCorp’s operating profit has continued to benefit from strong retail revenue growth, with increased customer usage and new customers contributing £40 million, favourable weather conditions contributing £21 million, sales mix adding £8 million and higher prices from regulatory recoveries coming through from Oregon, California and Wyoming, adding £11 million. These revenue upsides were partly offset by higher net power costs and other gross margin movements of £23 million reflecting the cost impact of higher retail loads, partly offset by a reduction in balancing volumes and the increased use of our own thermal generation at favourable prices. Other net costs increased by £20 million primarily as a result of pension and healthcare costs, maintenance charges, and costs of £5 million associated with the severe winter storms experienced in late December 2003 and early January 2004, partly offset by lower management costs. These increases were more than offset by PacifiCorp’s ongoing cost efficiency programme, which delivered £30 million of benefits in the year. Depreciation was higher by £23 million reflecting increased levels of capital investment throughout the business.
| Table 19 – PacifiCorp (£m)
|
2003/04 |
2002/03 | ||
| External turnover |
2,318.6 | 2,499.4 | ||
| Operating profit |
496.8 | 462.8 | ||
| Goodwill amortisation |
122.5 | 133.9 | ||
| Operating profit excluding goodwill |
619.3 | 596.7 | ||
PacifiCorp’s net investment in assets totalled £419 million, with £151 million (36%) of this invested for organic growth. Of this £126 million was invested in new transmission and system networks, including new connections and system reinforcement spend and in our major network expansion project along the Wasatch Front in Utah. New generation growth expenditure of £25 million included the ongoing construction of Currant Creek, the 525 MW peaking and baseload plant in Utah. Refurbishment and other expenditure totalled £268 million and included network investment, major overhauls of generation plant, mine equipment replacement, information technology and hydro relicensing. In May 2004 PacifiCorp announced it had selected Summit Vineyard LLC to construct a 534 MW gas-fired plant for approximately $330 million. The proposed new plant, named Lake Side, would be located near Salt Lake City, Utah, and would provide base load power starting in 2007. We are seeking regulatory approval for construction of the plant by December 2004.
ScottishPower Annual Report and Accounts 2003/04 39
Financial Review
Infrastructure Division
Infrastructure Division is our UK regulated wires business and is subject to price controls based on an allowed regulatory rate of return which is currently 6.5%. The regulatory rate of return is determined by periodic price reviews, and the division is working to secure a favourable outcome from the current distribution price review, the results of which will be effective from April 2005. The key financial information is shown in Table 20.
In the year, Infrastructure Division’s external turnover improved by £44 million to £358 million. In recent years, a significant proportion of Infrastructure Division’s sales have been internal to our UK Division, however, the impact of competition in our home markets has resulted in increases in external regulated income from third party suppliers. External turnover now accounts for just over half of Infrastructure’s total turnover. External electricity revenues have increased by £23 million in the year as a result of higher prices improving transmission turnover and higher volumes improving distribution turnover. Other revenues have grown by £21 million, including higher income arising from our new connections business of £27 million, offset by a reduction in other rechargeable work.
Infrastructure Division reported operating profit of £394 million, up £26 million for the year. Net regulated transmission and distribution use of system revenues increased by £13 million due to higher prices and volumes, and increased England-Scotland interconnector volumes contributed an additional £3 million to operating profit. Net operating costs were favourable by £6 million, primarily due to a change in the mix of capital and revenue activities undertaken and lower management costs. Property sale gains added a further £4 million to the operating profit improvement.
| Table 20 – Infrastructure Division (£m)
|
2003/04 |
2002/03 | ||
| External turnover |
358.3 | 314.0 | ||
| Operating profit |
393.6 | 367.8 | ||
Net investment in assets was £260 million for the year, with £60 million (23%) in organic growth areas such as new customer connections and network upgrading, including ongoing reinforcement projects in Dumfries & Galloway and Wrexham. The remaining £200 million of capital expenditure was primarily spent on refurbishing the network and included equipment replacement and modernisation programmes, which will improve system performance. Compared to last year we have increased investment in the replacement of network assets, and the total number of distribution network faults has reduced by 8.5% in the year.
UK Division
The UK Division is our competitive UK business and is committed to building on the substantial customer growth achieved during the year and to increasing its renewable energy portfolio. The key financial information is shown in Table 21.
Turnover within the UK Division increased by £630 million to £2,777 million for the year, with wholesale electricity activities contributing £380 million of the increase, retail and wholesale gas revenues contributing £193 million and higher retail electricity sales contributing £57 million.
Wholesale electricity sales in England & Wales, including exports, increased by £296 million in the year, as prices recovered and volumes increased by 13,737 GWh to 25,577 GWh. The volume growth was principally due to the division balancing its energy position more actively to minimise exposure to uncertain balancing mechanism prices and to protect against long-term price volatility. The increase in turnover caused by this activity was offset by a corresponding increase in purchase costs and as a result had minimal impact on operating profit. Other core wholesale revenues increased by £84 million from higher volume and priced agency sales, which are generation sales to third party suppliers in our Scottish home area, and other activities including the waste-derived-fuel plant at Daldowie which has now been in operation for a full year. Gas turnover increased by £193 million reflecting growth in wholesale volumes of 32%, mainly due to increased balancing activities, which had minimal impact on operating profit, and also due to growth in domestic gas customers of 32% and favourable wholesale and retail prices. Retail electricity sales improved by £57 million, with out-of-area revenues up by £62 million primarily as a result of growth in domestic customers, offset in part by loss of market share in our home areas due to competition. Total customer numbers have increased from 3.65 million to 4.25 million, with strong growth in domestic gas and out-of-area domestic electricity, being partly offset by loss of domestic electricity customers in our home Manweb area. Customer retention in our Scottish home area of 64% is in line with last year but the loss of customers in our Manweb area has resulted in overall retention of home area residential customers falling by 1% to 60% for the year, which is in line with the industry average.
The UK Division’s operating profit improved by £23 million to £96 million for the year and, excluding goodwill amortisation, increased by £23 million to £101 million. Improved margins across the business’s integrated value chain and continuing growth in customer numbers resulted in a £37 million increase in electricity margins. Gas margins improved by £2 million in the year due to favourable gas storage activities, which offset lower retail margins due to higher gas and transportation costs. Investment in energy efficiency and increased customer capture activities required to support customer growth, increased by £27 million, but were offset in part by a £14 million reduction in other net costs due to lower management costs. The contribution from other business activities reduced by £3 million, mainly due to the loss of a contract in our metering operations.
Similar to last year, the division utilised onerous contract provisions to bring the Peterhead and Rye House energy purchase costs more into line with market prices. The
40 ScottishPower Annual Report and Accounts 2003/04
provision relating to the Peterhead agreement was established in 1999/00 and related to onerous costs on contracted energy purchases, which were not expected to be recoverable. The remainder of this provision will be fully utilised by March 2005. Energy cost savings associated with the restructuring of the combined Peterhead and Hydro legacy electricity contracts with Scottish and Southern Energy will commence in 2005/06. The Rye House provision was established as part of the fair value accounting for the acquisition of the Rye House power station in 2000/01 and is expected to be utilised by 2008/09.
| Table 21 - UK Division (£m)
|
2003/04 |
2002/03 | ||
| External turnover |
2,777.4 | 2,147.8 | ||
| Operating profit |
96.1 | 73.0 | ||
| Goodwill amortisation |
4.9 | 4.9 | ||
| Operating profit excluding goodwill |
101.0 | 77.9 | ||
Net investment in assets for the year was £93 million, with £36 million (39%) of this invested in organic growth projects. This included investment in new wind generation of £26 million, with Cruach Mhor (30 MW) windfarm now fully commissioned and Black Law (96 MW) now under construction, following receipt of planning consent in February 2004. The project to upgrade and increase the capacity of the Cruachan pumped storage hydro station from 400 MW to 440 MW is near completion. Other capital investment of £57 million included the ongoing refurbishment and overhaul programme at our Longannet power station, which will improve the generation plant’s flexibility and capability, and hydro refurbishment works to allow the capture of Renewables Obligation Certificates (“ROCs”). The hydro refurbishment programme, which is ongoing at Stonebyres, Carsfad, Earlstoun and Drumjohn (34 MW combined) is due to complete by the end of 2004. Offshore windfarm activity is also progressing with the allocation of a second site from the Crown Estates Office auction. The Government granted planning permission in May 2004 for the construction of a highly flexible £100 million, 6 BCF gas storage facility near Byley, Cheshire. In the next financial year, the division aims to continue to invest in renewable generation capabilities with the objective of meeting its stated target of achieving 10% of electricity supply from renewable sources by 2010.
PPM
PPM is our competitive business in the US. The rate of PPM’s expansion will be determined by the availability of attractive market opportunities for growing its portfolio of assets, and also by public policy, on issues such as the extension of US Production Tax Credits (“PTCs”). The key financial information is shown in Table 22.
PPM’s turnover for the year improved by £57 million to £343 million, after a £25 million adverse US dollar translation impact. This increase was a result of increased sales of natural gas from fuel supply arrangements and optimisation activities around gas storage assets and contracts, and from new wind generation and gas storage expansion. Energy management turnover improved by £39 million with increased sales under fuel supply arrangements at the Klamath facility being partly offset by reduced counterparty demand for electricity output. New wind generation increased by £31 million primarily due to expanded output and turnover from new resources coming on line during the financial year. Gas storage turnover improved by £12 million, benefiting from the first full year of contribution from our Katy facility, acquired in December 2002, and increased ownership at the Alberta Hub.
PPM’s operating profit improved by £8 million ($18 million) to £36 million ($62 million) and, excluding goodwill amortisation, increased by £8 million ($18 million) to £37 million ($63 million). The contribution from the Katy and Alberta Hub gas storage facilities increased by £13 million in the year. Returns from new wind generation and other projects improved operating profits by £9 million and energy management activities from optimising storage asset capacities and natural gas sales added a further £4 million. Operating costs and depreciation, which underpin the business’s growth, increased by £16 million. The unfavourable impact of the weaker dollar on operating profit was £2 million.
| Table 22 – PPM (£m)
|
2003/04 |
2002/03 | ||
| External turnover |
342.8 | 285.9 | ||
| Operating profit |
36.1 | 28.3 | ||
| Goodwill amortisation |
0.6 | 0.2 | ||
| Operating profit excluding goodwill |
36.7 | 28.5 | ||
Net investment in assets for the year was £129 million, with £117 million (91%) invested in organic growth projects. Of this, more than £100 million was invested in new wind generation, with the construction of Flying Cloud (44 MW), Moraine (51 MW), Mountain View III (22 MW) and the Colorado Green joint venture (81 MW). These windfarms, all of which qualified for US PTCs and accelerated tax depreciation benefits, were commercially operational in the third quarter and are now contributing to business profits. In line with the group’s prudent energy management strategy, PPM has already sold forward approximately 80% of its wind power in contracts of between 10 and 25 years, locking in a regular “annuity” value. Other growth investment during the year included the purchase of an additional 17% ownership interest in the Alberta Hub, bringing PPM’s total ownership to 57%, and the commencement of a further gas storage development of 7.2 BCF at the Waha site in west Texas. The project is being developed in phases over six years, with the first phase operational by 2006. The remainder of PPM’s capital investment in the year was spent on growth development projects, information technology and refurbishment and overhaul of existing assets.
Discontinued Operations
There were no discontinued operations in the year to 31 March 2004. In the financial year 2002/03, discontinued operations
ScottishPower Annual Report and Accounts 2003/04 41
Financial Review
consisted of Southern Water. The disposal of Southern Water was completed on 23 April 2002 and turnover and operating profit generated in the period prior to disposal were £27 million and £14 million, respectively.
Net Assets
Prior year net assets have been restated for the impact of the Urgent Issues Task Force (“UITF”) Abstract 38 ‘Accounting for ESOP trusts’, which requires the group’s own shares held under trust to be deducted in arriving at shareholders’ funds. Further information on this is given in the Accounting Developments section on page 58 and in Note 17 to the Group Accounts, on page 107.
Group net assets increased by 3% in the year, from £4,629 million to £4,752 million, with our balance sheet hedging strategy significantly mitigating the adverse impact of the weaker US dollar.
Fixed assets reduced by £695 million to £10,807 million mainly as a result of the weaker US dollar, partly offset by our capital investment programme. Intangible assets, which represent goodwill arising on acquisition, reduced by £425 million, comprising £128 million of goodwill amortisation and a £297 million translation impact of the weaker US dollar on PacifiCorp and PPM goodwill. Tangible assets reduced by £272 million due to exchange movements on the translation of US balances of £771 million, depreciation charged to the profit and loss account of £439 million and disposals of £12 million, partly offset by gross capital expenditure of £949 million. Investments increased by £2 million mainly due to the £25 million spend on the Colorado Green joint venture windfarm, significantly offset by foreign exchange on the translation of US balances.
Current assets, excluding short-term bank and other deposits, decreased by £39 million to £1,652 million as at 31 March 2004. This was primarily due to the weaker US dollar reducing debtors, partly offset by higher gas stocks within PPM reflecting increased gas storage activities. The £403 million net cash receipt arising from the repricing of cross-currency swaps reduced debtors but this was partly offset by the effect of the weaker US dollar on the valuation of the total portfolio of financial instruments associated with our balance sheet hedging strategy. Debtors were also higher within the UK Division as a result of growth in customer numbers, tariff rises and increased energy balancing activities. Creditors due within one year, excluding loans and other borrowings, were £119 million lower than last year primarily as a result of the weaker US dollar, lower energy derivative contract creditors in PPM and a reduction in regulatory liabilities in PacifiCorp, offset by higher energy balancing and electricity purchase accruals within the UK Division.
Provisions for liabilities and charges decreased by £161 million to £1,747 million as at 31 March 2004. Of this, £60 million was attributable to deferred tax and £101 million to other provision movements. The other provision movements comprised an increase of £136 million of new provisions, mainly for pensions and other post-retirement benefits, and £20 million unwinding of discount, offset by £199 million of provisions utilised in the year, the majority being pensions and other post-retirement benefits and onerous contracts, and a £58 million reduction due to the weaker US dollar. Deferred income, which principally represents grants and customer contributions in our US and UK regulated businesses, increased by £19 million reflecting amounts receivable during the year of £48 million, net of £19 million released to the profit and loss account and £10 million of foreign exchange movements.
Total Recognised Gains and Losses
The Statement of Total Recognised Gains and Losses combines the profit for the year together with other gains and losses taken directly to reserves as required under UK GAAP. Total recognised gains for the year to 31 March 2004 were £522 million compared to £424 million for the prior year. This increase was as a result of £55 million growth in profit for the financial year and a £42 million favourable year on year movement in the net impact of foreign exchange movements and hedging of the group’s results and net assets. The weaker dollar exchange rates during the year resulted in unfavourable exchange movements of £538 million, which were largely offset by the benefits arising from our financial strategy to hedge foreign currency net assets of £475 million and favourable associated tax of £46 million, which included a credit of £48 million arising from the application of the transitional rules contained in the Finance Act 2002.
Significant Changes
Any significant developments and post-balance sheet events that have occurred since 31 March 2004 have been noted in the Annual Report and Accounts and the report on Form 20-F to be filed with the US Securities and Exchange Commission in 2004. Otherwise, there have been no significant changes since 31 March 2004.
4 Overview of the Year to March 2003
Group Profit and Loss
Group turnover for the year to 31 March 2003 was £5,274 million, a reduction of £1,040 million on 2001/02. From continuing operations, group turnover was lower by £276 million at £5,247 million including adverse translation movements of £205 million from the weaker US dollar. Sales were lower in PacifiCorp as a result of reduced wholesale power prices in the western US, although this was partially offset by revenue growth from our other three businesses.
PacifiCorp’s turnover was down by £481 million to £2,499 million mainly as a result of the lower wholesale prices experienced for most of 2002/03 and a £189 million adverse translation impact of the weaker US dollar. These reductions were offset in part by higher wholesale volumes and regulatory rate increases. Turnover for Infrastructure Division increased by
42 ScottishPower Annual Report and Accounts 2003/04
£66 million to £314 million. This was mainly due to increased regulated income from higher sales to third party electricity suppliers. The division also delivered non-regulated revenue growth of £28 million, principally due to increased new connections from its Core Utility Solutions joint venture. For the UK Division, turnover increased by £26 million to £2,148 million. This was as a result of higher sales to retail customers, increased generation agency sales in Scotland and exports to Northern Ireland which have offset the impact of low wholesale electricity prices. Turnover for PPM increased by £113 million to £286 million, after a £16 million adverse US dollar translation impact, as the business benefited from the first full year of its long-term power contracts and the growth of its gas storage business.
Discontinued operations’ turnover for 2002/03 reduced from £791 million to £27 million compared to 2001/02.
Cost of sales of £3,227 million were £1,184 million lower than 2001/02, with £479 million of this movement due to discontinued operations. Continuing operations’ cost of sales decreased by £705 million to £3,215 million primarily due to lower net power costs in PacifiCorp, offset in part by increased business activity at PPM. Transmission and distribution costs of £513 million were in line with 2001/02, with lower discontinued operations’ costs offset by increased costs for continuing operations due to higher insurance, rates and depreciation, principally in PacifiCorp and the Infrastructure Division. As a result of the demerger of Thus from the group, UK telephony and related expenses are now incurred externally and contributed to the increased costs. Administrative expenses (including goodwill amortisation) as shown in Table 23, were £81 million lower than in 2001/02, which included exceptional restructuring costs for the UK Division of £19 million. Administrative expenses, excluding goodwill amortisation and exceptional items, were £52 million lower than 2001/02, with discontinued operations accounting for £139 million of this movement. Continuing operations’ administrative expenses, excluding goodwill amortisation and exceptional items, were £474 million, an increase of £87 million compared to 2001/02. This increase was attributable to higher pension and other employee related costs throughout the group; higher depreciation charges and one-off gains in 2001/02 in PacifiCorp; and increased energy efficiency and customer capture costs in the UK Division. Depreciation for continuing operations increased by £33 million to £442 million reflecting the level of capital investment made in 2001/02. Depreciation for discontinued operations reduced by £140 million to £6 million.
| Table 23 – Administrative expenses (£m)
|
2002/03 |
2001/02 |
||||
| Administrative expenses |
614.5 | 695.1 | ||||
| Goodwill amortisation |
(139.0 | ) | (149.0 | ) | ||
| Exceptional items |
– | (18.5 | ) | |||
| Administrative expenses excluding goodwill & exceptionals |
475.5 | 527.6 | ||||
As shown in Table 24, group operating profit increased by £169 million to £946 million for the year to 31 March 2003. Group operating profit from continuing operations was £932 million, £297 million higher than 2001/02. Excluding goodwill amortisation and exceptional items, group operating profit from continuing operations increased by £270 million to £1,071 million. Our US operations delivered the majority of the increase. PacifiCorp contributed operating profit, excluding goodwill amortisation, of £597 million, an increase of £225 million on 2001/02. This was mainly due to lower net power costs, rate increases, regulatory recoveries of excess power costs and Transition Plan benefits. The Infrastructure Division’s operating profit of £368 million represented an increase of £13 million mainly due to higher regulated revenues and net cost savings. The UK Division’s operating profit, excluding goodwill amortisation, of £78 million was consistent with 2001/02, with the impact of low wholesale prices mitigated by our integrated approach to managing the energy value chain and the benefit from the settlement of the Nuclear Energy Agreement (“NEA”) with British Energy (“BE”). PPM reported operating profit of £28 million compared to a loss of £5 million in 2001/02, with the full year benefit of assets and contracts acquired in 2001/02 and continued progress made during 2002/03 in growing its portfolio of assets.
Operating profit from discontinued operations fell by £127 million to £14 million for 2002/03.
Goodwill amortisation of £139 million was £10 million lower than for 2001/02. This was due to the demerger of Thus in March 2002 and movements in US dollar exchange rates reducing the goodwill charge for PacifiCorp. Operating profit for the year to 31 March 2002 included an exceptional reorganisation charge of £19 million. This arose as a result of restructuring in the UK Division and included severance and related costs. There were no exceptional operating items in the year to 31 March 2003.
| Continuing operations |
Total operations | |||||||
| Table 24 – Group operating profit (£m)
|
2002/03 |
2001/02 |
2002/03 |
2001/02 | ||||
| Operating profit |
931.9 | 635.4 | 945.9 | 776.6 | ||||
| Goodwill amortisation |
139.0 | 146.6 | 139.0 | 149.0 | ||||
| Exceptional items |
– | 18.5 | – | 18.5 | ||||
| Operating profit excluding goodwill & exceptionals |
1,070.9 | 800.5 | 1,084.9 | 944.1 | ||||
There were no exceptional items in 2002/03. Exceptional items in 2001/02, including interest and tax, were £1,318 million. Included within this total were exceptional charges of £1,308 million related to the disposal of Southern Water, including the write back of goodwill previously taken to reserves, and the disposal of and withdrawal from Appliance Retailing. The other exceptional items in 2001/02 were reorganisation costs of £19 million, interest of £31 million and a tax credit on exceptional items of £39 million.
The net interest charge for 2002/03 as shown in Table 25 of £254 million was £156 million lower than the charge for 2001/02 which included exceptional interest of £31 million. The exceptional interest principally related to the restructuring of the
ScottishPower Annual Report and Accounts 2003/04 43
Financial Review
group debt portfolio prior to the sale of Southern Water. Excluding exceptional interest, the charge was £125 million lower. This was attributable to substantially lower net debt following the sale of Southern Water, together with lower US interest rates, a change in the fixed/variable debt profile and favourable exchange benefits from the weaker US dollar. The lower interest charge also included a benefit of £46 million associated with our dollar hedging strategy. UK interest, excluding the benefit of our dollar hedging strategy, was £104 million, a reduction of £103 million on 2001/02. The interest charge for the US increased by £24 million to £196 million, principally as a result of higher underlying debt.
| Table 25 – Interest (£m)
|
2002/03 |
2001/02 |
|||
| Interest |
254.3 | 410.2 | |||
| Exceptional interest |
– | (30.8 | ) | ||
| Interest excluding exceptional interest |
254.3 | 379.4 | |||
The tax charge as shown in Table 26 of £209 million was £126 million higher than the charge for 2001/02. The main reasons for the increase were the tax credit on exceptional items of £39 million included in the 2001/02 charge, higher pre-tax profit in 2002/03 due to improved operational performance and a higher effective rate of tax. The effective tax rate increased to 25%, from the 2001/02 rate of 21.5% on profit excluding goodwill amortisation and exceptional items. The increase was due to a greater proportion of group profit being derived from our US operations, which are subject to a higher rate of tax. The effective tax rate benefits from the release of prior period provisions, following agreement with the tax authorities on treatment of specific items and the financial structure of the group. The tax charge was £209 million on profit before tax of £697 million, compared to a tax charge of £83 million on a loss before tax of £939 million in 2001/02.
| Table 26 – Tax (£m)
|
2002/03 |
2001/02 | ||
| Tax |
209.0 | 83.2 | ||
| Exceptional tax credit |
– | 38.8 | ||
| Tax excluding exceptional tax credit |
209.0 | 122.0 | ||
Profit after tax, as shown in Table 27, increased by £1,510 million to £488 million. This increase was due to exceptional items in 2001/02 of £1,318 million, improved operational performance in our continuing operations in 2002/03 and lower interest charges, partly offset by the profit reduction from our discontinued operations. Excluding exceptional items and goodwill amortisation, profit after tax increased by £182 million to £627 million with profit after tax for continuing operations, improving by £226 million to £619 million. With a weighted average 1,844 million shares in issue during 2002/03, earnings per share, as shown in Table 28, improved from a loss of 53.7 pence for the year to 31 March 2002 to earnings of 26.2 pence in the year to 31 March 2003, due to the reasons mentioned above. Excluding goodwill amortisation and exceptional items, group earnings per share for 2002/03 were 33.7 pence, an increase of 7.6 pence and 33.3 pence for continuing operations, an increase of 12.3 pence.
| Continuing operations |
Total operations |
||||||||
| Table 27 – Profit/(loss) after tax (£m)
|
2002/03 |
2001/02 |
2002/03 |
2001/02 |
|||||
| Profit/(loss) after tax |
480.2 | 220.9 | 487.8 | (1,022.0 | ) | ||||
| Goodwill amortisation |
139.0 | 146.6 | 139.0 | 149.0 | |||||
| Exceptional items including interest & tax |
– | 26.0 | – | 1,318.1 | |||||
| Profit after tax excluding goodwill & exceptionals |
619.2 | 393.5 | 626.8 | 445.1 | |||||
| Continuing operations |
Total operations |
||||||||
| Table 28 – Group earnings/(loss) per share (pence)
|
2002/03 |
2001/02 |
2002/03 |
2001/02 |
|||||
| Earnings/(loss) per share (EPS) |
25.76 | 11.65 | 26.17 | (53.71 | ) | ||||
| EPS impact of goodwill amortisation |
7.54 | 7.98 | 7.54 | 8.11 | |||||
| EPS impact of exceptional items |
– | 1.41 | – | 71.72 | |||||
| EPS excluding goodwill & exceptionals |
33.30 | 21.04 | 33.71 | 26.12 | |||||
Total cash dividends per share for 2002/03 of 28.708 pence were consistent with our stated aim of a 5% annual increase in dividends to 31 March 2003. Dividends in 2001/02 included a ‘dividend in specie’ of £437 million arising on the demerger of Thus on 19 March 2002.
Business Reviews
PacifiCorp
The key financial information is shown in Table 29.
PacifiCorp turnover was £2,499 million in 2002/03, a reduction of £481 million on 2001/02 mainly due to lower wholesale electricity prices experienced for most of the year. Excluding the effect of foreign exchange, wholesale revenues were £409 million lower than 2001/02. There was a decrease in average short-term and spot market wholesale prices in 2002/03 and lower long-term volumes. This was partially offset by higher short-term and spot volumes and long-term prices. Factors contributing to the lower market price included new generation brought on-line in the western US, the continuing effect of the Federal Energy Regulatory Commission market mitigation, and milder weather and economic conditions affecting demand growth. Residential and commercial revenues increased by £9 million (1.4%) and £10 million (2.1%) respectively, mainly as a result of higher prices and growth in customer numbers, offset by lower average customer usage due to milder weather. Industrial revenues were down by £4 million (0.8%) as the impact of lower volumes, due to a weaker economy, more than offset higher prices and increased irrigation revenues. Other revenue growth, primarily as a result of excess power cost recoveries in Utah and Oregon, were more than offset by lower wheeling revenues and unfavourable foreign exchange movements.
Operating profit for PacifiCorp increased by £233 million to £463 million for the year to 31 March 2003. Operating profit, excluding goodwill amortisation, for PacifiCorp grew by £225 million to £597 million, as a result of regulatory rate increases
44 ScottishPower Annual Report and Accounts 2003/04
and recoveries of excess power costs of £80 million, significantly lower net power costs of £257 million and continued progress in the delivery of Transition Plan benefits of £64 million. These improvements were partly offset by lower transmission revenues of £19 million from reduced use of the transmission system by third parties, higher depreciation charges of £25 million, risk mitigation and project costs of £41 million, insurance, pensions and healthcare costs of £46 million, and one-off gains in 2001/02 and foreign exchange of £45 million.
| Table 29 – PacifiCorp (£m)
|
2002/03 |
2001/02 | ||
| External turnover |
2,499.4 | 2,980.7 | ||
| Operating profit |
462.8 | 229.9 | ||
| Goodwill amortisation |
133.9 | 141.7 | ||
| Operating profit excluding goodwill |
596.7 | 371.6 | ||
Infrastructure Division
The key financial information is shown in Table 30.
External turnover within the Infrastructure Division increased by £66 million for 2002/03 to £314 million. Infrastructure Division’s sales were mainly internal to our UK Division, however, the impact of competition on our home markets resulted in an increase in regulated income from third party electricity suppliers of £38 million. Other revenue growth of £28 million was also delivered from external non-regulated sales, principally due to increased new connections from the Core Utility Solutions joint venture.
Infrastructure Division reported operating profit of £368 million for 2002/03, an increase of £13 million on 2001/02. Higher regulated income of £9 million and net cost reductions of £18 million were partly offset by higher depreciation, operational rates, insurance and pension costs of £14 million.
| Table 30 – Infrastructure Division (£m)
|
2002/03 |
2001/02 | ||
| External turnover |
314.0 | 247.6 | ||
| Operating profit |
367.8 | 354.9 | ||
UK Division
The key financial information is shown in Table 31.
UK Division turnover increased by £26 million to £2,148 million for 2002/03. Although wholesale market prices were down, agency turnover increased by £17 million due to volume growth, and exports to Northern Ireland increased by £19 million, following the first full year of trading. Total sales in England & Wales, including exports, decreased by £13 million due to adverse prices, partly offset by favourable volumes. Wholesale gas volumes increased by 1.4 billion therms, however, lower prices resulted in sales revenues dropping by £10 million on 2001/02. Retail supply turnover grew by £11 million with higher retail gas sales of £52 million and increased turnover from out-of-area customer gains of £53 million, partially offset by loss of market share and lower sales prices in our home areas, which reduced turnover by £94 million. Other revenues increased by £2 million. Customer numbers increased to 3.65 million in 2002/03, and retention of home area residential customers stood at 61%.
Operating profit for the UK Division increased by £18 million to £73 million for the year to 31 March 2003, mainly due to the 2001/02 results including a £19 million exceptional reorganisation charge. Operating profit, excluding goodwill amortisation and exceptional items, was £78 million for 2002/03, £1 million lower compared to 2001/02. Net energy margins performed strongly, increasing by £15 million before higher depreciation, costs to capture and investment in energy efficiency schemes of £12 million and increased pension costs of £4 million. The impact of lower wholesale electricity prices has been mitigated by our integrated approach to managing the energy value chain whereby our own electricity production is extensively matched to our customer demand across Great Britain. The renegotiation of the NEA with BE at a market related price delivered a benefit of approximately £25 million in 2002/03 and provided a hedge against revenues which have been impacted by lower wholesale prices.
| Table 31 – UK Division (£m)
|
2002/03 |
2001/02 | ||
| External turnover |
2,147.8 | 2,121.4 | ||
| Operating profit |
73.0 | 55.3 | ||
| Goodwill amortisation |
4.9 | 4.9 | ||
| Exceptional items |
– | 18.5 | ||
| Operating profit excluding goodwill & exceptionals |
77.9 | 78.7 | ||
PPM
The key financial information is shown in Table 32.
Turnover for PPM for 2002/03 increased by £113 million to £286 million, after a £16 million adverse US dollar translation impact, as the business benefited from the first full year of its Klamath and Stateline long-term power contracts and growth of its gas storage business, including the Katy gas storage facility acquired in December 2002.
PPM reported an operating profit of £28 million for 2002/03, compared to a loss of £5 million in 2001/02. The growth in operating profit was due to the increased contribution from long-term sales contracts and gas storage activities and optimisation benefits of £53 million, partly offset by higher depreciation charges and other operating costs of £17 million to support business growth and the benefit from settlement of a £3 million contract in 2001/02.
| Table 32 – PPM (£m)
|
2002/03 |
2001/02 |
|||
| External turnover |
285.9 | 173.1 | |||
| Operating profit/(loss) |
28.3 | (4.7 | ) | ||
| Goodwill amortisation |
0.2 | – | |||
| Operating profit/(loss) excluding goodwill |
28.5 | (4.7 | ) | ||
Discontinued Operations
Discontinued operations consisted of Southern Water, Appliance Retailing and Thus for the year to 31 March 2002 and Southern Water for the year to 31 March 2003. The disposal of Southern
ScottishPower Annual Report and Accounts 2003/04 45
Financial Review
Water was completed on 23 April 2002 and turnover and operating profit generated in the period prior to disposal were £27 million and £14 million, respectively. The disposal of and withdrawal from Appliance Retailing was completed by 31 March 2002 and the Thus demerger was completed in March 2002.
In 2002/03, discontinued operations’ turnover decreased from £791 million to £27 million, compared to 2001/02. Of this reduction, £403 million was due to Southern Water, £229 million to Thus and £132 million to Appliance Retailing.
Discontinued operations’ operating profit for 2002/03 reduced by £127 million to £14 million, with Southern Water profit decreasing by £202 million, partly offset by reduced losses in Thus and Appliance Retailing of £66 million and £9 million, respectively.
Total Recognised Gains and Losses
Total recognised gains for the year to 31 March 2003 were £424 million, compared to losses for 2001/02 of £1,006 million, which included £1,318 million of net exceptional charges (after interest and tax). Excluding the net exceptional charges, total recognised gains increased by £112 million compared to 2001/02, as a result of £152 million growth in profit for the financial year, offset by the net impact of foreign exchange movements and hedging of the group’s results and net assets. The weaker dollar exchange rates during 2002/03 resulted in unfavourable exchange movements of £387 million, which were largely mitigated by the benefits of £358 million, less tax of £29 million, arising from our strategy to hedge foreign currency net assets.
ScottishPower supports research into development of the generation, transmission, distribution and supply of electricity. It also continues to contribute, on an industry-wide basis, towards the cost of research into electricity utilisation and distribution developments. In financial years 2003/04, 2002/03 and 2001/02, expenditure on research and development in the group’s businesses was £0.2 million, £0.7 million and £3.1 million, respectively.
6 Liquidity and Capital Resources
The treasury focus during the year continued to be to minimise interest costs and effectively manage both foreign exchange and interest rate risk. The group continues to ensure that borrowings are financed from a variety of competitive sources and that committed facilities are available both to cover uncommitted borrowings and to meet the financing needs of the group in the future. A further priority was to maximise the return on investment of the group’s cash balances while avoiding excessive credit risk.
Interest
The net interest charge for the year to 31 March 2004, as shown in Table 33, of £238 million was £16 million lower than the charge for the previous year. This reduction was mainly attributable to the favourable exchange benefits from the weaker US dollar of £17 million and lower interest rates in both the US and UK. The lower interest charge also included a benefit of £39 million associated with our dollar balance sheet hedging strategy (2002/03: £46 million), whereby the group swaps out of sterling liabilities into dollar liabilities in order to hedge its US$ 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. Excluding the benefit of our dollar hedging strategy, underlying UK interest was £107 million, an increase of £3 million on last year. In the US the interest charge reduced by £26 million to £170 million, principally as a result of favourable exchange rates and lower interest rates. Interest, adjusted for foreign exchange gains and losses, as shown in Table 33, is covered by profit on ordinary activities before interest, excluding goodwill amortisation, shown in Table 34, 4.9 times for the year to 31 March 2004, improved from 4.3 times for the previous year. Interest is covered by profit on ordinary activities before interest 4.3 times, up from 3.7 times in the previous year.
As at 31 March 2004, 84% of the group’s net borrowings were fixed for periods of more than one year. In accordance with the group’s revised interest policy, the group is moving towards its target of a long-term benchmark of 70% fixed rate and 30% floating rate interest. Further discussion on interest rate policy is included within the Market Risk section on page 53.
| Table 33 – Interest (£m)
|
2003/04 |
2002/03 |
|||
| Interest |
238.1 | 254.3 | |||
| Foreign exchange loss |
– | (0.5 | ) | ||
| Interest excluding foreign exchange loss |
238.1 | 253.8 | |||
| Table 34 – Profit before interest (£m)
|
2003/04 |
2002/03 | ||
| Profit before interest |
1,030.2 | 951.1 | ||
| Goodwill amortisation |
128.0 | 139.0 | ||
| Profit before interest excluding goodwill |
1,158.2 | 1,090.1 | ||
Balance Sheet Hedging
The group has currently hedged $5,900 million (2002/03: $5,000 million), representing approximately 92% of its US net assets. In addition to the $700 million convertible bonds issued during the year, liabilities have been created for periods out to March 2012, by means of cross-currency swaps and foreign exchange forwards totalling $5,200 million.
Cash Flow and Net Debt
Table 35 provides a reconciliation of EBITDA (earnings before interest, tax, depreciation and amortisation) to net cash inflow from operating activities, and, as such, effectively demonstrates how the group has converted operating profit into cash. During the year, £1.4 billion of EBITDA was converted into cash, with the remaining £0.2 billion being either invested in working capital to support growth of our competitive businesses, or being
46 ScottishPower Annual Report and Accounts 2003/04
attributable to provision movements, mainly relating to onerous contracts within the UK Division. Working capital requirements increased within the UK Division as a result of the significant growth in customer numbers and higher tariffs, and in PPM gas stocks were higher as a result of natural gas purchases for energy management activities. Net cash provided by operating activities is impacted by seasonal movements in working capital throughout the year.
| Table 35 – Reconciliation of EBITDA to net cash inflow from operating activities (£m)
|
2003/04 |
2002/03 |
||||
| Operating profit |
1,022.6 | 945.9 | ||||
| Share of operating profit in joint ventures & associates |
7.6 | 5.2 | ||||
| Depreciation & amortisation |
566.7 | 586.2 | ||||
| EBITDA |
1,596.9 | 1,537.3 | ||||
| Share of operating profit in joint ventures & associates |
(7.6 | ) | (5.2 | ) | ||
| Other non-cash movements 1 |
(15.0 | ) | (5.9 | ) | ||
| Movement in provisions for liabilities & charges |
(87.6 | ) | (77.5 | ) | ||
| Working capital 2 |
(122.7 | ) | (35.8 | ) | ||
| Net cash inflow from operating activities |
1,364.0 | 1,412.9 | ||||
| 1 | Profit/loss on sale of tangible fixed assets; amortisation of share scheme costs; release of deferred income |
| 2 | Increase/decrease in stock, debtors & creditors |
Net cash interest costs were £205 million compared with a profit and loss account charge of £238 million reflecting timing differences on the settlement of interest costs, the unwinding of discount on provisions and capitalised interest. Cash taxation was £122 million compared with a profit and loss account charge of £248 million. This reflects both cash tax timing differences arising from the group’s investment programme and the cash tax benefit of the transitional rules of the Finance Act 2002, reported in the Statement of Total Recognised Gains and Losses.
Net cash receipts arising from the repricing of cross-currency swaps were £403 million and proceeds from the cancellation of cross-currency swaps as a result of the issue of the $700 million convertible bonds was £76 million. Net proceeds arising from the issue of new debt and repayment of existing borrowings were £464 million and principally represented the issue of the convertible bonds, PacifiCorp bond issues and the redemption of PacifiCorp preferred securities of £205 million.
In total, the above net cash inflows were sufficient to fund the group’s capital expenditure and financial investment of £831 million, and dividend payments of £394 million, as well as contribute to the reduction in net debt reported in the year. The cash outflow of £354 million associated with the management of liquid resources represented the transfer of cash into highly liquid non-demand deposits, such as bonds.
Net debt at 31 March 2004 was £3,725 million, £597 million lower than at 31 March 2003, with the translation impact of the weaker dollar and other non-cash movements reducing net debt by £362 million. Included in net debt are short-term bank and other deposits (including the liquid resources referred to above) of £1,347 million, up £683 million on the prior year principally as a result of the cash proceeds from repricing of cross-currency swaps and new debt issues in the year. Total debt balances increased from £4,986 million to £5,072 million with the translation impact and other non-cash changes of £380 million and repayments of £389 million offset by new borrowings of £855 million.
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.
Management and external credit rating agencies utilise a number of financial ratios when assessing the performance of our business, and our financing arrangements are also subject to a number of ratio-based covenants contained within our principal credit agreements. Two of the main ratios monitored by ScottishPower management are gearing (net debt/equity shareholders’ funds) which reduced to 79% from 95% at 31 March 2003 and the ratio of net debt/EBITDA which is a measure used in banking covenants. EBITDA is shown in Table 36 and net debt/EBITDA improved from 2.8 times last year to 2.3 times, benefiting from improved EBITDA and a lower debt position which includes the benefit of the weaker US dollar.
| Table 36 – EBITDA (£m)
|
2003/04 |
2002/03 | ||
| Profit before interest & tax |
1,030.2 | 951.1 | ||
| Depreciation & amortisation |
566.7 | 586.2 | ||
| EBITDA |
1,596.9 | 1,537.3 | ||
Financing
The group’s external borrowings have generally been sourced in two separate pools. In the UK, Scottish Power UK plc (“SPUK”) 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. During the year, for the first time, Scottish Power plc (“SP plc”), the ultimate holding company, raised funds by means of a $1,000 million bank facility and the $700 million convertible bonds issue.
In both the UK and the US, regulatory constraints apply to financing activities. SP plc is not permitted to borrow from its subsidiaries with the exception of certain intermediate holding companies in the US ownership chain and is currently financed by way of dividends and external debt. During the year, SP plc’s two £50 million bilateral 364-day committed facilities were cancelled, concurrent with the arrangement of two new committed revolving credit facilities totalling $1,000 million. The two facilities, a five-year facility of $625 million and a 364-day facility of $375 million, represent varying commitments from a number of relationship banks. Both were un-drawn at
ScottishPower Annual Report and Accounts 2003/04 47
Financial Review
the year-end. SP plc’s new revolving credit facilities contain financial covenants relating to interest cover (operating profit to net interest payable not less than 2.5 to 1), dividend cover (earnings to consolidated dividends not less than 1.25 to 1) and the ratio of net debt to EBITDA (not greater than 4.0 to 1). The company has not breached these covenants throughout the year to 31 March 2004.
In the UK, Scottish Power Finance (Jersey) Limited has issued $700 million bonds which are convertible into shares in SP plc. The bonds are guaranteed by SP plc. There have been no new issues in the year under ScottishPower’s euro-medium-term note programme, established in November 1997. Cumulative issues outstanding under the programme now total some $2,571 million against a programme limit of $7,000 million. SP plc and SPUK are the issuers under the programme.
During the year SPUK has not added to its index-linked liabilities, currently totalling £275 million. Total borrowings from the European Investment Bank (“EIB”) amounted to £199 million. The EIB debt within SP Manweb plc contains financial covenants relating to interest cover (EBITDA to net interest payable not less than 4.0 to 1) and net debt to EBITDA (not greater than 4.0 to 1) of SP Manweb plc. SP Manweb plc has not breached these covenants throughout the year to 31 March 2004.
The UK distribution, transmission and generation subsidiaries have provided upstream guarantees to support the majority of SPUK’s debt that existed at 1 October 2001, following their incorporation to comply with the Utilities Act 2000. As at 31 March 2004, the total amount of debt guaranteed by the three companies amounted to £2,148 million. New debt issued by SPUK after 1 October 2001 is not permitted to benefit from the guarantee of SPUK’s subsidiaries, SP Distribution Limited and SP Transmission Limited.
During the year to 31 March 2004, PacifiCorp issued new long-term debt in the form of two first mortgage bonds of $200 million each, with maturities of September 2008 and September 2013. Respective coupons are 4.3% and 5.45%. These were issued to fund the redemption of higher cost preferred securities and previously redeemed medium-term notes. In addition, scheduled repayments of $137 million were made during the year. PacifiCorp has an effective shelf registration statement for up to $650 million of long-term debt of which $400 million has been authorised to be issued by the applicable regulatory commissions, subject to certain conditions. Any such issuance would be subject to market conditions. PacifiCorp has debt maturities out as far as 2031/32.
In June 2003, PacifiCorp replaced its expiring $500 million 364-day facility with a similar facility having a maturity of June 2004. This is in addition to an existing $300 million three-year facility maturing in June 2005. These two bank facilities are provided by core relationship banks, the majority of which are common to both the US and UK bank facilities. PacifiCorp’s principal debt limitations are a 60% debt to defined capitalisation test and an interest coverage covenant (EBITDA/interest of 2.0 to 1), contained in its principal credit agreements. PacifiCorp has been in compliance with these covenants throughout the year to 31 March 2004. In addition, under the Public Utility Holding Company Act of 1935 there are restrictions on the ability of group companies to lend to or borrow from one another.
SP plc and PacifiCorp are both currently seeking to replace their respective 364-day revolving credit facilities that mature in June 2004. PacifiCorp is currently seeking to replace its existing facility on terms and conditions similar to the maturing facility. SP plc is currently seeking to increase its remaining 4-year revolving credit facility by the amount of the maturing 364-day facility. When completed SP plc will have a $1,000 million revolving credit facility with a coterminous maturity date of June 2008. While the group expects that both these facilities will be successfully replaced no assurance can be given as to the outcome.
Credit Ratings
SP plc, SPUK and PacifiCorp have credit ratings published by some or all of Standard & Poor’s Ratings Group (“S&P”), Moody’s Investors Service (“Moody’s”) and The Fitch Group (“Fitch”) as shown in Table 37. PacifiCorp Group Holdings, a subsidiary of PacifiCorp Holdings Inc., has slightly lower ratings although they remain investment grade. Ratings from S&P and Moody’s are on negative outlook. These security ratings are not recommendations to buy, sell or hold securities. The ratings are subject to change or withdrawal at any time by the respective credit rating agencies. Each credit rating should be evaluated independently of any other rating.
| Table 37 – Credit ratings
|
S&P |
Moody’s |
Fitch | |||
| SP plc |
A- | Baa1 | n/a | |||
| SPUK (long-term) |
A- | A2 | A- | |||
| PacifiCorp (senior secured) |
A | A3 | A | |||
| PacifiCorp (unsecured) |
BBB+ | Baa1 | A- | |||
| SPUK and PacifiCorp (short-term) |
A-2 | P-2 | F-1 |
Any adverse change to credit ratings of group companies could negatively impact on their ability to access capital markets and on the rates of interest that they would be charged for such access. The EIB debt within SP Transmission Limited and SP Distribution Limited contains credit downgrade language, which does not constitute default, but means that, should the ratings of SP Transmission Limited or SP Distribution Limited fall, the EIB will be entitled to ask for additional security in the form of a guarantee acceptable to the EIB. PacifiCorp has no rating downgrade triggers within its debt instruments, although interest rates on loans under its bank facilities and commitment fees on the facilities would increase with a ratings downgrade.
The investment of surplus cash is undertaken to maximise the return within Board approved policies which govern the ratings criteria, maximum investment and the
48 ScottishPower Annual Report and Accounts 2003/04
maturity with any one counterparty. Counterparties are required to have a short-term rating of at least A-1, P-1 or F-1 from one of the three major rating agencies.
Contractual Obligations and Commercial Commitments
The group enters into various financial obligations and commitments in the normal course of business. Contractual financial obligations are considered to comprise known future cash payments that the group is required to make under contractual arrangements in place at 31 March 2004. Commercial commitments are defined as those obligations of the group, which only become payable if certain pre-defined events occur.
Table 38 details the group’s contractual obligations at 31 March 2004.
| Payments due by period | ||||||||||
| Table 38 – Contractual obligations at 31 March 2004 (£m)
|
Less than 1 year |
1 – 3 years |
3 – 5 years |
More than 5 years |
Total | |||||
| Loans and other borrowings (including overdrafts) |
410.7 | 505.4 | 707.5 | 3,433.2 | 5,056.8 | |||||
| Finance leases |
– | 0.4 | 0.6 | 14.0 | 15.0 | |||||
| Operating leases |
12.2 | 15.6 | 9.1 | 33.0 | 69.9 | |||||
| PacifiCorp preferred stock |
2.0 | 4.1 | 26.5 | – | 32.6 | |||||
| Energy purchase commitments |
1,725.0 | 1,533.0 | 749.7 | 2,078.3 | 6,086.0 | |||||
| Capital commitments |
98.1 | 4.5 | 0.6 | 2.6 | 105.8 | |||||
| Other firm commitments |
91.7 | 116.0 | 70.7 | 351.6 | 630.0 | |||||
| Total |
2,339.7 | 2,179.0 | 1,564.7 | 5,912.7 | 11,996.1 | |||||
The loans and other borrowings figures in Table 38 are stated at book value at 31 March 2004.
Energy purchase agreements included within Table 38 arise principally from short- and long-term purchase power and fuel contracts. Further detailed information on power purchase commitments is set out in Note 30 to the Group Accounts on page 127.
Other firm commitments included within Table 38 arise principally from transportation, transmission and storage commitments and costs associated with hydroelectric licences, asset retirement obligations and information technology services.
The group’s commercial commitments include surety bonds that provide indemnities for PacifiCorp in relation to various commitments it has to third parties for obligations in the event of default on behalf of PacifiCorp. The majority of these bonds are continuous in nature and renew annually. The estimates are based on current information and actual amounts may vary due to rate changes or changes to the general operations of PacifiCorp.
The group invested £901 million in its asset base during the year ended 31 March 2004. The group’s estimated net investment in its asset base for the year ended 31 March 2005, which is subject to continuing review and revisions, is approximately £1.2 billion, based on a US dollar/UK sterling exchange rate of approximately $1.80, and represents investment in organic growth projects and refurbishment.
Going Concern
The directors confirm that the group remains a going concern on the basis of its future cash flow forecasts and has sufficient working capital for present requirements.
7 Quantitative and Qualitative Disclosures about Market Risk
Market Rate Sensitive Instruments and Risk Management
The following discussion about the group’s risk management activities includes “forward-looking” statements that involve risk and uncertainties. Actual results could differ materially from those projected in the forward-looking statements.
The Tables in Note 20 to the Group Accounts on pages 109 to 114 summarise the financial instruments, including derivative instruments and derivative commodity instruments, held by the group at 31 March 2004, which are sensitive to changes in interest rates, foreign exchange rates and commodity prices. The group uses interest rate swaps, forward foreign exchange contracts and other 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 (as above) 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, businesses 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
Overview
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,
ScottishPower Annual Report and Accounts 2003/04 49
Financial Review
foreign exchange risk, liquidity risk and derivative risk. The Board has reviewed and agreed policies for managing each of these risks as summarised below. In order 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, forward-rate agreements, financial and commodity forward contracts, commodity futures, commodity options and weather derivatives.
Energy Risk Management
Energy risk is governed globally (with oversight from the Executive Team) by the Group Energy Risk Committee (“GERC”), chaired by the Finance Director with membership from the divisions and the independent risk management team. The GERC defines, and the ScottishPower Board approves, the group risk management policies and limits as well as the UK and the US risk policies and limits. These policies and limits, as well as the GERC approved procedures, are designed to create consistent risk measurement, monitoring and management standards throughout the group. The monitoring and management of the level of exposure covered is handled by the businesses, with full oversight by a corporate risk management function, independent of the businesses, reporting to the Finance Director. The businesses with commodity exposure are authorised to manage this exposure using approved products, policies and limits. These businesses each report no less frequently than monthly to a local risk committee, as well as to the GERC.
Market exposures are quantified and controlled using a number of different risk measures. These include Value-at-Risk (“VaR”) methods for earnings volatility control. VaR is a statistically based measure of the potential financial loss on a price exposure position over a defined period to a given level of confidence. VaR computations for the group’s energy commodity portfolios are based on a historical simulation technique. This technique utilises historical energy market forward price curve changes over a specified period to simulate potential forward price curve changes to estimate the potential unfavourable impact of price changes in the portfolio positions scheduled to settle within the forward 24 months. The quantification of market risk using VaR provides a consistent measure of risk across the group’s continually changing portfolio. VaR represents an estimate of reasonably possible changes in fair value that would be measured on its portfolio assuming hypothetical movements in future market rates, and is not necessarily indicative of actual results that may occur. Future changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.
The group’s VaR computations for its energy commodity portfolio utilise several key assumptions, including a 99% confidence level for the resultant price changes and a holding period of five business days. The calculation includes short-term commodity transactions and commodity derivative instruments held for trading and balancing purposes, the expected resource and demand obligations from the group’s long-term contracts, the expected generation levels from the group’s generation assets and the expected retail and wholesale load levels. Optionality embedded within the group’s bilateral contracts, generation assets and other derivative instruments with option characteristics within the energy portfolio are treated in the historical simulation of VaR as static expected or delta adjusted positions through the simulation process. Expected positions and option deltas are recalculated on a daily basis to determine the portfolio position changes due to changes in market prices.
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. Additional risk measures are being developed to quantify risks beyond the confidence intervals defined in the VaR methodology and determine volumetric risks in physical positions. We apply stress tests to reinforce our VaR conclusions and have introduced stochastic analysis to estimate the impact of risks on outcomes.
Energy Price and Volume Risk Management
UK Division
The New Electricity Trading Arrangements (“NETA”) was introduced in England & Wales on 27 March 2001, replacing the previous ‘Pool’ mechanism for the sale and purchase of wholesale power in England & Wales. NETA provides for a bilateral wholesale market, with suppliers, traders and generators trading firm physical forward contracts for bulk electricity supply. In addition to transacting to directly manage our market price exposure in the England & Wales market, the UK Division also manages its price exposure arising from sales within the Scottish market by the use of forward contracts.
The balancing mechanism, operated from one hour ahead of real-time (gate closure) up to real-time by the National Grid Company, is used to manage the England & Wales grid system on a second-by-second basis. Market participants can participate actively in this market through the submission of bids and offers to vary their output as a generator or demand as a customer. The mechanism also provides for calculation and settlement of imbalance charges arising from the differences between parties’ contract positions and their actual physical energy flows. Since wind output from several UK Division-owned wind generation facilities located within the UK is dispatched directly as generated into the UK electricity distribution system, this wind output contributes to such imbalance charges.
The UK Division has procedures in place to minimise exposure to uncertain balancing mechanism prices, that is, the possibility that the UK Division will face high charges for shortfalls in physical energy or receive low revenues for surplus physical energy. These procedures involve the UK Division entering into bilateral contracts for the sale and purchase of energy across a
50 ScottishPower Annual Report and Accounts 2003/04
range of time periods to minimise exposure to the balancing mechanism. In addition, our portfolio of flexible generating assets in England and Scotland can be used up to gate closure to minimise further this exposure and also to attract premium income from providing flexible power to the balancing mechanism.
The UK Division has also entered into longer-term (in excess of one year) arrangements to protect against longer-term volatility of power prices. The time periods covered by these longer-term arrangements are reviewed on a continuous basis to provide the desired level of price stability.
The UK Division also has procedures in place to minimise exposure to natural gas price variations. In a similar manner to our power price exposure management strategy, natural gas price risk is managed through a combination of longer-term contracts and shorter-term trading contracts with flexible delivery profiles, certain derivative financial instruments and through the use of flexibility within our portfolio of electricity generation and natural gas storage assets. The UK Division mitigates its exposure to coal price risk through the use of a combination of financial and physical contracts as well as currency hedges executed by the ScottishPower treasury function. Cover against volatile spot prices is built up on a rolling basis through the year and, at 31 March 2004, a significant proportion of the UK Division’s exposure to electricity, natural gas and coal price variations for the following financial year have been mitigated.
The UK Division measures the market risk in its energy portfolio daily utilising the VaR approach (described above), stress tests as well as other measurements of net position, and monitors its portfolio exposure to market risk in comparison to established thresholds. The UK Division also measures its open positions at price risk in terms of volumes at each significant delivery location for each forward time period.
As at 31 March 2004, the UK Division’s estimated potential five-day unfavourable impact on fair value of the energy commodity portfolio over the next 24 months was £8.8 million, as measured by the VaR computations (described above), compared to £11.8 million as at 31 March 2003. The average daily VaR (five-day holding) for the year ended 31 March 2004 was £9.3 million. The maximum and minimum VaR measured during the year ended 31 March 2004 were £13.7 million and £5.0 million, respectively. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.
PacifiCorp
PacifiCorp’s market risk to commodity price change is primarily related to its natural gas and electricity purchases and sales arising principally from its electricity supply obligation in the US. As in the UK, this risk to price change is subject to fluctuations in weather, economic growth and generation resource availability which impacts supply and demand. For example, during April and May 2004, PacifiCorp experienced higher than average temperatures and lower than normal hydro conditions. Risk limits are established to govern energy purchases and sales. Price risk is managed principally through the operation of its generation and transmission system in the western US and through its wholesale energy purchase and sales activities. Physically settled contracts are used to hedge PacifiCorp’s excess or shortage of net electricity for future months. PacifiCorp has a forecast net balanced position for the summer periods of 2004 and 2005.
While PacifiCorp plans for resources to meet its current and expected retail and wholesale load obligations, resource availability, price volatility and volumetric volatility around both load and resources may materially impact the power costs to PacifiCorp and profits from surplus power sales in the future. Prices paid by PacifiCorp to provide certain load balancing resources to supply its load may exceed the amounts it receives through retail rates and wholesale prices. Prices received by PacifiCorp to dispose of resources made excess by changes in retail and wholesale load obligations may fall short of the amounts PacifiCorp has paid for such resources. In the 2000/01 power crisis, regulatory approval of deferred accounting treatment under US GAAP for these excess costs mitigated a portion of this price risk to the extent that recovery mechanisms were implemented. Recovery of amounts allowed by the public utility commissions are scheduled to continue through at least 2004/05. However, such deferred accounting treatment was granted in the extraordinary circumstance of the power crisis and subsequent use of this mechanism is not automatic and is not guaranteed for future use.
PacifiCorp continues to actively manage commodity price volatility and reduce exposure. These steps include adding to its generation portfolio and entering into transactions that help to expand and shape PacifiCorp’s system resource portfolio, including physical hedging products and financially settled weather (temperature-related) derivative instruments that reduce volume and price risk on days with weather extremes. In addition, hydrogeneration hedges have been put in place for the next two years to limit volume and price risks associated with Pacific Northwest hydrogeneration availability.
PacifiCorp measures the market risk in its natural gas and electricity portfolio daily utilising the VaR approach (described above), as well as other measurements of net position, and monitors its portfolio exposure to market risk in comparison to established thresholds. PacifiCorp also measures its open positions at price risk in terms of volumes at each significant delivery location for each forward time period.
At 31 March 2004, PacifiCorp’s estimated potential five-day unfavourable impact on fair value of the natural gas and electricity commodity portfolio over the next 24 months was £10.0 million, as measured by the VaR computations (described above), compared to £11.0 million at 31 March 2003. The average daily VaR (five-day holding) for the year ended 31 March 2004 was £9.0 million. The maximum and minimum VaR measured during the year ended 31 March 2004 were £14.5 million and £5.0 million, respectively. Changes in markets
ScottishPower Annual Report and Accounts 2003/04 51
Financial Review
inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.
PPM
PPM is ScottishPower’s competitive US energy company, which is primarily focused on providing environmentally responsible energy products to wholesale customers. The strategic priorities of PPM are to grow its renewable/thermal energy portfolio and natural gas storage/hub services business and optimise returns through the integration of assets, trading and commercial activities. PPM’s strategy is to match the capacity and output of PPM assets and long-term sales obligations. Imbalances between asset positions and long-term sales are managed via wholesale energy purchases and sales activities.
PPM owns the output from a number of wind generation facilities located throughout the US. Associated with the wind energy production are Renewable Energy Certificates (“RECs”) that represent the environmental attributes of the renewable energy. Consistent with its overall portfolio strategy, PPM balances its wind asset position with long-term forward sales and some spot sales of both energy and renewable attributes. Wind generation resource availability and variability is subject to price changes for that portion of the output that is not committed to long-term fixed price bilateral contracts. Imbalances in the REC portfolio are subject to price changes in the REC market.
PPM owns or manages over 800 MW of thermal capacity on its own behalf and on the behalf of third parties. Substantially all of this capacity is committed to long-term contracts, with the imbalance being subject to generation resource availability and the relationship of fuel (natural gas) costs to electricity prices (or “spark spread”). PPM manages short-term and daily imbalance through real-time markets. PPM’s risk in this business is principally if counterparties fail to perform in accordance with contracts and if PPM’s generation assets fail to perform at reasonable levels.
PPM also owns natural gas storage facilities and contracted natural gas storage capacity in Canada, Texas and other locations. PPM’s strategy is to develop a natural gas storage/hub services business that will own and operate facilities across North America. Through a process of prudent risk limits, established risk information systems and clear reporting, PPM’s gas storage business model is designed to minimise commodity risk. PPM provides a service for a fee for both long-term and short-term hub services. Hub services is a generic term used to describe various fee-based transactions carried out by the storage operator such as parking and loaning of natural gas or the “wheeling” of natural gas from one pipeline to another at the storage location. As a result, the hub services business is subject to the risks associated with the operations and marketing of the storage facilities and services.
Subject to market risk limitations delegated by ScottishPower and oversight by the corporate risk management group, PPM may maintain or create open positions in response to (or in anticipation of) long-term origination or development transactions creating exposure to market price movements. As such, PPM will participate in the wholesale electricity and natural gas markets to manage its open positions. In addition, PPM engages in point-of-view energy management activities in accordance with strict limits approved by the business unit risk committee (chaired by the group risk management function). Control and performance metrics for such activities are tracked daily.
PPM measures the market risk in its natural gas and electricity portfolio daily utilising the VaR approach (described above), as well as other measurements of net position, and monitors its portfolio exposure to market risk in comparison to established thresholds. PPM also measures its open positions at price risk in terms of volumes at each delivery location for each forward time period.
At 31 March 2004, PPM’s estimated potential five-day unfavourable impact on fair value of the energy commodity portfolio over the next 24 months was £5.8 million, as measured by the VaR computations (described above), compared to £2.4 million at 31 March 2003. The average daily VaR (five-day holding) for the year ended 31 March 2004 was £3.1 million. The maximum and minimum VaR measured during the year ended 31 March 2004 were £6.2 million and £1.1 million, respectively. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.
Credit Risk Management
The role of the group’s credit function is to set consistent standards for assessing, quantifying (scoring), monitoring, mitigating and controlling the credit risk introduced by contractual obligations of wholesale trading partners and industrial and commercial clients. A group credit committee operating alongside the GERC provides umbrella oversight to ensure a consistent approach to counterparty rating, and limit management is adopted across the group and oversees the allocation of limits to those counterparties that overlap both the US and the UK markets. This group credit committee ensures that each individual business is subject to concentration rules that prevent misallocation of credit risk amongst counterparties. Beneath the group credit committee, the UK and the US credit committees provide local expertise to understanding the credit environment in each geographic location. All decisions are supported by rigorous measurement and reporting of credit exposures and the use of credit rating models. Credit approvals are subject to regular and/or event driven reviews.
Counterparties for energy commodity transactions must meet the following requirements: (a) transaction counterparties must be investment grade (rated BBB- or better) to avoid posting collateral or otherwise perfect their credit, while (b) non-rated or less than BBB- rated counterparties must either have a guarantee from an investment grade entity, post collateral or provide other assurances deemed acceptable to the group credit committee and GERC.
52 ScottishPower Annual Report and Accounts 2003/04
Treasury Management
The group treasury function is authorised to conduct the day-to-day treasury activities of the group within policies set out by the Board. The group treasury function reports regularly to the Board, through the monthly Group Performance and Risk Report and is subject to internal audit.
Interest Rate Risk Management
The group continues to manage its interest rate exposure by maintaining a percentage of its debt at fixed rates of interest. This is done either directly by means of fixed rate debt issues or by use of interest and cross-currency swaps to convert variable rate debt into fixed rate debt and fixed/variable non-functional currency denominated debt into fixed rate functional currency debt. The use of derivative financial instruments relates directly to underlying existing and anticipated indebtedness.
The exposure to fluctuating interest rates is managed by either issuing fixed or floating rate debt or using a range of financial derivative instruments to create the desired fixed/floating mix. The group’s interest rate policy is to target a long-term benchmark of 70% fixed rate and 30% floating rate interest, with the floating rate portion being protected from interest rate rises for up to one year ahead by means of forward rate agreements. At 31 March 2004, 84% (2003: 77%) of the net debt was either issued as fixed or converted to fixed rates using interest rate swaps. The weighted average period to maturity of year-end fixed debt and interest swaps was 9 years (UK 10 years, US 9 years). Based on net floating rate debt of £212 million at 31 March 2004, a 1% change in interest rates at that date would result in a £2.1 million change in profit before tax over a twelve-month period.
All treasury transactions are undertaken to manage the risks arising from underlying activities and no speculative trading is undertaken. The counterparties to these instruments generally consist of financial institutions and other bodies rated at least “AA-” by one of S&P, Moody’s or Fitch. Although the group is potentially exposed to credit risk in the event of non-performance by counterparties, such credit risk is controlled through credit rating reviews of the counterparties and by limiting the total amount of exposure to any one party to levels agreed by the Board. The group does not believe that it is over exposed to any material concentration of credit risk.
Inflation Risk Management
In recognition of the fact that a portion of UK revenues are linked to inflation, SPUK maintains part of its debt portfolio in index-linked liabilities. This is done either through issues of debt or through swapping fixed rate debt into index-linked. Index-linked liabilities total £275 million, which represents around 10% of the UK debt portfolio.
Insurance Risk Management
Where cost effective, the group maintains a wide-ranging insurance programme providing financial protection, predominately against catastrophic risks. In the past year, the upward pressure on insurance costs experienced since 2002 has eased considerably. Although some classes of insurance are still increasing in cost, during 2003/04, 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 2004/05 has been completed delivering a net premium reduction.
Foreign Exchange Risk Management
Translation Risk
The principal objective of our currency risk management and hedging strategy is to seek to mitigate exposure to movements in foreign exchange rates for both dollar denominated net assets and earnings, taking into account its potential effect on our net debt and related credit statistics. The aim is to hedge nearly 100% of US net assets with dollar liabilities. This is done by a combination of borrowing dollars in the UK, by swapping sterling debt into dollars or by creating additional dollar liabilities (and corresponding sterling assets) to the extent that total net dollar assets exceed UK based debt. The resulting stream of dollar interest acts as a natural partial hedge to the translation of US profits. US profits are greater than interest paid in dollars and the resulting gap is hedged either by UK based purchases of coal (which is traded in dollars) or by selling dollars in order to mitigate the impact of exchange rate movements. All foreign currency derivative contracts are subject to the same controls as interest rate derivatives referred to above.
Any foreign currency denominated debt will be subject to re-translation at period end closing rates. A ten cent (5%) strengthening of the 31 March 2004 closing US dollar exchange rate would give rise to a £144 million increase in reported net debt at 31 March 2004.
Transaction Risk
Other than the import of coal in the UK, transactions denominated in a foreign currency are not numerous in the group. Where they arise as a result of imports of capital or other goods denominated in foreign currencies the exposure is hedged as soon as it is committed.
Liquidity Risk Management
In recognition of the long life of the group’s assets and anticipated indebtedness, and to create financial efficiencies, the group’s policy is to arrange that debt maturities are spread over a wide range of dates, thereby ensuring that the group is not subject to excessive refinancing risk in any one year. The group has entered into borrowing agreements for periods out to 2039. The weighted average period to maturity of year-end debt was ten years. The group had undrawn committed revolving credit facilities totalling $1,800 million as at 31 March 2004 which provide backstop liquidity should the need arise. Liquidity in the UK is currently supported by the remaining cash held from the
ScottishPower Annual Report and Accounts 2003/04 53
Financial Review
proceeds of the Southern Water sale, the convertible bonds issue and the repricing of cross-currency swaps amounting in total to £1,090 million.
Derivative Risk
The use of derivative financial instruments relates directly to underlying existing and anticipated indebtedness, foreign subsidiary earnings and net assets and business transactions denominated in foreign currencies.
During the year, cross-currency swaps with a principal value of $2,550 million hedging the US dollar net assets of the US business were repriced, reducing credit exposure on derivatives to several counterparties and releasing net cash of £403 million. At the same time, foreign exchange forwards hedging US net assets were closed out and replaced with cross-currency swaps. Also during the year, we received cash of £76 million from the cancellation of cross-currency swaps hedging the US dollar net assets, as a direct result of the issue of the $700 million convertible bonds, which effectively replaced the hedge. 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.
Credit risk on non-energy commodity derivative transactions is mitigated by a policy of only using counterparties with a credit rating of AA- or above. Exposure to derivative counterparties is monitored using measures, dependent on the type of transactions, that take into account potential market volatility.
8 Fair Value of Derivative Contracts
The group uses derivative instruments in the normal course of business to offset fluctuations in earnings, cash flows and equity associated with movements in exchange rates, interest rates and commodity prices. In limited circumstances the group holds derivative financial instruments for energy management purposes. These derivatives are marked to market and unrealised gains and losses are recognised in the group’s profit and loss account. The net unrealised gains on financial assets and liabilities held for trading at 31 March 2004 was £0.6 million. Table 39 details the changes in the fair value of the group’s energy related and treasury derivative contracts which are subject to the requirements of Statement of Financial Accounting Standard (“FAS”) No. 133 ‘Accounting for Derivative Instruments and Hedging Activities’, as amended. FAS 133 requires, for the purposes of US GAAP, all derivatives, as defined by the standard, to be marked to market value, except for those which qualify for specific exemption under the standard or associated 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 fall outside the scope of FAS 133. In addition, the effect of 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’. These amounts are expected to be recovered through rate cases. The FAS 133 liability relating to PacifiCorp of £225.7 million, as set out in Table 39, is offset under US GAAP by a US regulatory net asset of £229.7 million.
The forward price curves for energy commodity prices are derived using market price quotations when available and are developed internally using models when market quotations are unavailable. Market quotations are received from independent energy brokers and reporting services, as well as direct information received from third party offers and actual transactions entered into by the group, for certain actively traded locations covering the first three years. For the less actively traded locations and periods extending past three years, the forward price curves are developed internally using various models that are intended to simulate expected market price levels. Long-term prices generally are derived using a fundamentals model (cost-to-build approach) that is updated at least quarterly, to reflect changes in the market. Prices for less actively traded locations are developed based on historically observed price relationships with actively traded locations. Short-term energy contracts, without explicit or embedded optionality, are valued based upon the relevant portion of the forward price curve. Energy contracts with explicit or embedded optionality and long-term energy contracts are valued by separating each contract into its physical and financial forward, swap and option components. Forward and swap components are valued against the appropriate market curve. The optionality is valued using a modified Black-Scholes model or a stochastic simulation (Monte Carlo) approach. Each option component is modelled and valued separately using the appropriate forward price curve.
Interest rate swaps and forward-rate agreements are valued by calculating the present value of future cash flows estimated using forward market curves.
Interest rate swaptions are valued using the market yield curve and implied volatilities at the period end. Cross-currency swaps are valued by adding the present values of the two legs of each swap: present values are calculated by discounting the future cash flows, estimated using the appropriate forward market curve for that currency, at the appropriate market discount rates. Forward foreign exchange contracts are valued using market forward exchange rates at the period end.
In Table 39 changes in fair values attributable to changes in valuation techniques and assumptions reflect changes in the fair value of mark-to-market values as a result of applying refinements in valuation modelling techniques.
54 ScottishPower Annual Report and Accounts 2003/04
Other changes in fair value reflect changes in underlying economic fundamentals which impact on the value of the derivative including commodity price risk, which is influenced by contract size, term, location and unique or specific contract terms; movements in foreign exchange rates which impact the value of cross-currency swaps; and movements in interest rates which impact on the value of interest rate swaps, forward-rate agreements and cross-currency swaps.
| Table 39 – Fair value of energy related and treasury derivative contracts (£m)
|
PacifiCorp |
PPM |
UK Division |
Treasury |
Total |
||||||||||
| Fair value of contracts outstanding at 1 April 2003 |
(319.9 | ) | 173.6 | 40.6 | 373.8 | 268.1 | |||||||||
| Contracts realised or otherwise settled during the year |
26.7 | (30.6 | ) | (1.2 | ) | (51.5 | ) | (56.6 | ) | ||||||
| Changes in fair values attributable to changes in valuation techniques and assumptions |
(26.7 | ) | – | 2.3 | – | (24.4 | ) | ||||||||
| Other changes in fair value |
53.7 | 3.5 | 27.5 | 54.0 | 138.7 | ||||||||||
| Foreign exchange movement |
40.5 | (22.2 | ) | – | – | 18.3 | |||||||||
| Fair value of contracts outstanding at 31 March 2004 |
(225.7 | ) | 124.3 | 69.2 | 376.3 | 344.1 | |||||||||
As shown in Table 40, standardised derivative contracts that are valued using market quotations are classified as prices based on quoted market prices from third party sources. All remaining contracts, which include non-standard contracts and contracts for which market prices are not routinely quoted, are classified as prices based on models and other valuation methods.
| Table 40 – Maturity profile of fair value of derivative contracts outstanding (£m)
|
Within 1 year |
Between 1 – 3 years |
Between 3 – 5 years |
After 5 years |
Total | |||||||
| Prices based on quoted market prices from third party sources |
42.8 | 47.3 | 37.3 | 1.1 | 128.5 | |||||||
| Prices based on models and other valuation methods |
193.4 | 155.0 | (23.8 | ) | (109.0 | ) | 215.6 | |||||
| Total |
236.2 | 202.3 | 13.5 | (107.9 | ) | 344.1 | ||||||
As required by the transitional arrangements for Financial Reporting Standard (“FRS”) 17 ‘Retirement Benefits’, we have disclosed, at 31 March 2004, a deficit of £120 million (2003: £231 million) net of deferred tax for our UK defined benefit pension schemes and a deficit of £180 million ($331 million) (2003: £214 million ($338 million)) net of deferred tax for our US schemes. With the obligation to fund other post-retirement benefits in the US, we have also reported a deficit under FRS 17 at 31 March 2004 of £96 million ($177 million) (2003: £122 million ($193 million)), net of deferred tax. Had the measurement rules within FRS 17 been applied during the financial year 2003/04, the group’s operating profit would have increased by £24 million (2002/03: £5 million), finance costs would have increased by £15 million (2002/03: decreased by £31 million) and profit before tax would have increased by £9 million (2002/03: £36 million). Net assets and reserves at 31 March 2004 would have been reduced by £311 million (2003: £479 million).
FRS 17 prescribes detailed rules for the calculation of pension scheme assets and liabilities and indicates the net accounting surplus or deficit that would exist on an ongoing basis using market conditions at the balance sheet date. Fluctuations in investment conditions can result in significant volatility in funding levels.
Pension schemes are, however, managed over the long-term. Investment and liability decisions are based on underlying actuarial and economic circumstance with the intention of making sure that the schemes have sufficient assets to meet liabilities as they fall due, rather than meeting accounting requirements. The company and the trustees of the group’s schemes have reviewed the investment strategy for the asset/liability matching of the group’s schemes and this has resulted in agreement to a gradual shift towards a higher element of bond/gilt holdings from equities.
The charge in the year for these pension schemes, as reflected in the group profit and loss account, is based on Statement of Standard Accounting Practice (“SSAP”) 24 ‘Accounting for pension costs’. The charge on this basis has increased from £16 million to £28 million in the UK, and from £26 million ($41 million) to £39 million ($71 million) in the US. Contribution payments to the UK schemes recommenced during the financial year. Achieving regulatory recovery of these costs is a priority and we have a focus on ensuring inclusion of any increased expense in US rate cases and the regulatory Price Control Reviews in the UK and this is already being achieved in recent US rate cases.
10 Creditor Payment Policy and Practice
In the UK, the group’s current policy and practice concerning the payment of its trade creditors is to follow the Better Payment Practice Code to which it is a signatory. Copies of the Code may be obtained from the Department of Trade and Industry or from the website www.payontime.co.uk.
The group’s policy and practice is to settle terms of payment when agreeing the terms of the transaction, to include the terms in contracts and to pay in accordance with its contractual and legal obligations. The group’s creditor days at 31 March 2004 for its UK businesses and US businesses were 18 days and 41 days, respectively.
ScottishPower Annual Report and Accounts 2003/04 55
Financial Review
11 Critical Accounting Policies – UK GAAP
The group’s Accounts are prepared in accordance with UK GAAP. This requires the directors to adopt those accounting policies which are most appropriate for the purpose of the Accounts giving a true and fair view. The group’s material accounting policies are set out in full on pages 86 to 89. In preparing the Accounts in conformity with UK GAAP, the directors are required to make estimates and assumptions that impact on the reported amounts of revenues, expenses, assets and liabilities. Actual results may differ from these estimates. Certain of the group’s accounting policies have been identified as critical accounting policies by considering which policies involve particularly complex or subjective decisions or assessments and these are discussed below. The discussion below should be read in conjunction with the full statement of Accounting Policies. The critical accounting policies have been discussed with the group’s senior management and the Audit Committee.
UK GAAP – Turnover
Prices for electricity supplied to the group’s retail customers in the US are determined by the relevant regulatory authorities. In the group’s UK Division, prices for electricity and gas supplied to retail customers are determined within competitive markets. In both cases, the assessment of energy sales to customers is based on meter readings, which are carried out on a systematic basis throughout the year. At the end of each accounting period, amounts of energy delivered to customers since the last billing date are estimated and the corresponding unbilled revenue is estimated and recorded as sales. Unbilled revenues included within the group's balance sheet relating to the group’s retail customers at 31 March 2004 amount to £256 million (2003: £183 million).
UK GAAP – Environmental Provisions
Provision is made for liabilities relating to environmental obligations when the related environmental disturbance occurs, based on the net present value of estimated future costs. Estimates of environmental liabilities are principally based on reports prepared by external consultants. The ultimate cost of environmental disturbance is uncertain and there may be variances from these cost estimates, which could affect future results. At 31 March 2004, the group had provided £60.5 million (2003: £85.2 million) for environmental obligations.
UK GAAP – Decommissioning and Mine Reclamation Provisions
Provision is made for the decommissioning of major capital assets where the costs are incurred at the end of the lives of the assets. Similarly, closure and reclamation costs are a normal consequence of mining with the majority of the expenditure incurred at the end of the life of the mine. Although the ultimate cost to be incurred is uncertain, estimates have been made of the respective costs based on local conditions and requirements. At 31 March 2004, the group had provided £84.3 million (2003: £83.3 million) for decommissioning costs and £79.6 million (2003: £72.3 million) for mine reclamation costs.
UK GAAP – Tax
The group’s tax charge is based on the profit for the year and tax rates in force. Estimation of the tax charge requires an assessment to be made of the potential tax treatment of certain items which will only be resolved once finally agreed with the relevant tax authorities. In particular, the tax returns of the group’s US businesses are examined by the Internal Revenue Service and state agencies on a several year lag. Assessment of the likely outcome of the examinations is based upon historical experience and the current status of examination issues.
UK GAAP – Provisions and Contingencies
In accounting for contingencies, the group applies FRS 12 ‘Provisions, contingent liabilities and contingent assets’. FRS 12 requires that a provision be recognised where there is a present obligation as a result of a past event, it is probable that a transfer of economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. If these conditions are not met, no provision should be recognised. However, contingent liabilities are required to be disclosed in the Notes to the Group Accounts, unless the possibility of a transfer of economic benefits is remote. Contingent gains are not recognised unless realisation of the profit is virtually certain.
Provisions are established when required based upon the directors’ best judgement. Appropriate disclosures are made regarding litigation, tax matters, environmental issues, among others. The evaluation of these contingencies is performed by various specialists inside and outside of the group. Accounting for contingencies requires significant judgement by management regarding the estimated probabilities and ranges of exposure to potential loss. The directors’ assessment of the group’s exposure to contingencies could change as new developments occur or more information becomes available. The outcome of the contingencies could vary significantly and could materially impact the group’s results and financial position. The directors have used their best judgement in applying FRS 12 to these matters.
UK GAAP – Pensions and Other Post-Retirement Benefits
The group operates a number of defined benefit schemes for its employees. In addition, other post-retirement benefits are provided to employees within the group’s US businesses. The group accounts for these arrangements under UK GAAP in accordance with SSAP 24. The impact on the group’s Accounts had the measurement rules of FRS 17 been implemented is summarised in the Pension Arrangements section on page 55.
The expense and balance sheet items relating to the group’s accounting for pension schemes under SSAP 24 are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, earnings increases
56 ScottishPower Annual Report and Accounts 2003/04
and pension increases in payment. These actuarial assumptions are reviewed periodically and modified as appropriate. The effect of modifications is generally amortised over future periods. The assumptions adopted are based on prior experience, market conditions and the advice of plan actuaries.
Where, as in 2002/03, there are significant market changes in the interim period between formal actuarial valuations, the effect of such changes is recognised in calculating pension costs.
The group chooses a discount rate for each scheme which reflects yields on high-quality fixed-income investments, which may be increased for SSAP 24 purposes to allow for higher returns expected over the longer-term from the schemes’ equity holdings. The pension liability and future pension expense both increase as the discount rate is reduced.
If the SSAP 24 expense for the year ended 31 March 2004 had been based on a discount rate 0.5% p.a. higher or lower than those actually used, the expense would have reduced or increased, respectively, by £18 million in respect of the group’s UK pension schemes and £5 million in respect of the group’s US pension schemes.
The discount rates used for the purposes of UK GAAP for the group’s principal pension schemes are set out in Table 41. Discount rates may vary between schemes as a result of different investment strategies, liability profiles and timing of the actuarial valuations.
| Table 41 – Discount rates | Discount rate | |||||
| Pension fund |
– UK GAAP (SSAP 24) |
Discount rate – US GAAP |
||||
| ScottishPower |
6.0 | % | 5.5 | % | ||
| Manweb |
6.0 | % | 5.5 | % | ||
| PacifiCorp |
6.75 | % | 6.25 | % |
12 Critical Accounting Policies – US GAAP
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. The adjustments required to reconcile the group’s profit or loss and shareholders’ funds from UK GAAP to US GAAP are explained in Note 34 to the Group Accounts. Certain of the group’s US GAAP accounting policies have been identified as critical US GAAP accounting policies and these are discussed below. The discussion below should be read in conjunction with the full discussion of the differences between the group’s UK and US GAAP accounting policies set out in Note 34.
US GAAP – US Regulatory Assets
The group prepares its US GAAP financial information in accordance with FAS 71 in respect of its regulated US business, PacifiCorp.
In order to apply FAS 71, certain conditions must be satisfied, including the following: an independent regulator must set rates; the regulator must set the rates to cover the specific costs of delivering service; and the service territory must lack competitive pressures to reduce rates below the rates set by the regulator. FAS 71 requires the group to reflect the impact of regulatory decisions and requires that certain costs be deferred on the balance sheet under US GAAP until matching revenue can be recognised. FAS 71 provides that regulatory assets may be capitalised, under US GAAP, if it is probable that future revenues, in an amount at least equal to the capitalised costs, will result from the inclusion of that cost in allowable costs for rate making purposes. In addition the rate actions should permit recovery of the specific previously incurred costs, rather than to provide for expected levels of similar future costs. An entity applying FAS 71 does not need absolute assurance prior to capitalising a cost, only reasonable assurance. Based on the group’s US regulatory net asset balance under US GAAP at 31 March 2004, if the group stopped applying FAS 71 to its remaining regulated US operations, it would have recorded a loss after tax, of £445.0 million under US GAAP. PacifiCorp intends to seek recovery of all of its prudent costs, including stranded costs, in the event of deregulation. However, due to the current lack of definitive legislation, it is not possible to predict whether PacifiCorp will be successful.
Because of potential regulatory and/or legislative actions in the various states in which PacifiCorp operates, the group may have regulatory asset write offs and charges for impairment of regulatory assets, under US GAAP, in future periods. Such impairment reviews would involve estimates of future cash flows including estimated future prices, cash costs of operations, sales and load growth forecasts and the nature of any legislative or regulatory cost recovery mechanism.
US GAAP – Impairment of Goodwill
FAS 142 ‘Goodwill and Other Intangible Assets’ deals with the accounting for goodwill and other intangible assets upon their acquisition and their subsequent measurement. The standard requires that goodwill is not amortised but is tested for impairment at least annually. Under FAS 142, the impairment test is in two stages. The first step is a screen for potential impairment. This compares an estimate of the fair value of the reporting unit that contains the goodwill with the carrying value of the net assets (including goodwill) in the balance sheet of that reporting unit. If this identifies a potential impairment then the second step is required. This requires assigning fair values to the assets and liabilities of the reporting unit (similar to what would be required under acquisition accounting). The difference between the fair value of these net assets and the estimate of the fair value of the reporting unit as a whole provides an implied fair value of the goodwill. If this implied fair value is less than the carrying value of the goodwill, then goodwill is impaired and an impairment charge requires to be recognised. In accordance with the requirements of the standard, the group performed an initial impairment test on the relevant reporting units on
ScottishPower Annual Report and Accounts 2003/04 57
Financial Review
implementation of the standard and has thereafter performed its annual review at 30 September 2002 and 30 September 2003. The reviews have confirmed that the fair values of the reporting units exceeded the carrying value of the net assets of the reporting units and that, therefore, no impairment of the goodwill has occurred. Nevertheless, the requirement, under US GAAP, that goodwill is not amortised implies that the reporting unit being tested must generate sufficient new goodwill to replace that which was recognised on acquisition. The fair value of the reporting unit is assessed by reference to a combination of recent market transactions where available and the present value of the expected future cash flows of the reporting unit. Estimates of future cash flows involve a significant degree of judgement but are consistent with management’s plans and forecasts. For the purposes of the standard the group has determined its reporting units to be at the same level as its reported segments.
US GAAP – Derivative Financial Instruments
The group accounts for its derivative financial instruments under US GAAP in accordance with FAS 133, as amended. FAS 133 requires, for the purposes of US GAAP, all derivatives, as defined by the standard, to be recorded at fair value except for those which qualify for specific exemptions under the standard, such as the normal purchases and normal sales exemption. Changes in the fair values of derivatives that are not designated as hedges are adjusted through earnings under US GAAP with the exception of long-term energy contracts that were in existence on 1 April 2001 and are included in PacifiCorp’s rate making base. For these long-term energy contracts PacifiCorp received regulatory accounting orders to adjust the fair value through regulatory assets or liabilities, reversing recorded amounts as the contracts settle. For derivatives designated as effective cash flow hedges, the changes in fair values are recognised under US GAAP in accumulated other comprehensive income until the hedged items are recognised in earnings. For derivatives designated as effective fair value hedges, the changes in fair values are recognised under US GAAP in the income statement, offset to the extent that they are effective, by fair value movements on the designated risk of the item being hedged. The group’s future results under US GAAP could be impacted by changes in market conditions to the extent that changes in contract values are not offset by regulatory or hedge accounting.
US GAAP – Pensions and Other Post-Retirement Benefits
The group accounts for its pension schemes under US GAAP in accordance with FAS 87 ‘Employers’ Accounting for Pensions’. Under FAS 87, certain of the group’s pension schemes had assets with a fair value at 31 March 2004 that was less than the accumulated benefit obligation under the schemes at the same date. As a result, at 31 March 2004 the group recognised a minimum pension liability under US GAAP of £316.4 million, of which £193.3 million was charged to accumulated other comprehensive income and £123.1 million was recognised as a US regulatory asset. If a discount rate had been used for accumulated benefit obligation purposes which was 0.5% p.a. higher than that actually used, the impact would have been to reduce the minimum pension liability by £47 million in respect of the group’s UK pension schemes and £38 million in respect of the group’s US pension schemes. The discount rates used for the purposes of US GAAP for the group’s principal pension schemes are set out in Table 41.
UK GAAP Developments Applicable for the Year to March 2004
During the year ended 31 March 2004 the UK Accounting Standards Board (“ASB”) issued one new standard, on revenue recognition, in the form of an Application Note to FRS 5 ‘Reporting the substance of transactions’. The Application Note sets out the basic principles of revenue recognition, and specifically addresses five types of arrangements that give rise to turnover. The group implemented this new standard in the financial year ended 31 March 2004, which had no impact on the group’s results for the year or on the group’s previously reported turnover.
In December 2003, the UITF committee of the ASB issued Abstract 38 ‘Accounting for ESOP trusts’ which supersedes Abstract 13, which dealt with the same topic, and amends Abstract 17 ‘Employee share schemes’. The new Abstract changes the presentation of an entity’s own shares held in an ESOP trust from requiring them to be recognised as assets to requiring them to be deducted in arriving at shareholders’ funds. Abstract 17 is amended by Abstract 38 to reflect the consequences for the profit and loss account of the changes in the presentation of an entity’s own shares held by an ESOP trust. Amended Abstract 17 requires that the minimum expense should be the difference between the fair value of the shares at the date of award and the amount that an employee may be required to pay for the shares (i.e. the ‘intrinsic value’ of the award). The expense was previously determined either as the intrinsic value or, where purchases of shares had been made by an ESOP trust at fair value, by reference to the cost or book value of shares that were available for the award. These new accounting requirements are mandatory for accounting periods ending on or after 22 June 2004. The group has implemented these new and revised Abstracts in the financial year ended 31 March 2004 and prior year figures have been restated accordingly. The net reduction in shareholders’ funds as at 31 March 2003 was £83.4 million.
UK GAAP Developments Applicable in the Future
In April 2004 the ASB issued FRS 20 ‘Share-based Payment’. The new standard has the effect of implementing, in the UK, International Financial Reporting Standard (“IFRS”) 2 ‘Share-based Payment’, which was published in February 2004 by the International Accounting Standards Board (“IASB”). The requirements of FRS 20 are virtually identical to those of IFRS 2.
58 ScottishPower Annual Report and Accounts 2003/04
In May 2004, the ASB issued FRS 21 ‘Events after the Balance Sheet Date’. The new standard has the effect of implementing, in the UK, International Accounting Standard (“IAS”) 10 (revised) ‘Events after the Balance Sheet Date’, which was published in December 2003 by the IASB. The requirements of FRS 21 are virtually identical to those of IAS 10 (revised).
From 2005/06, however, ScottishPower will be required to prepare its consolidated Accounts in compliance with IFRS (as discussed in the International Financial Reporting Standards section on pages 60 and 61). The group will, therefore, be subject to IFRS 2 and IAS 10 (revised) rather than FRS 20 and FRS 21.
US GAAP Developments Applicable for the Year to March 2004
In June 2001, the Financial Accounting Standards Board (“FASB”) issued FAS 143 ‘Accounting for Asset Retirement Obligations’ which became effective for the group on 1 April 2003. The standard requires the fair value of an asset retirement obligation to be recorded as a liability in the period in which the obligation is incurred. At the same time as the liability is recorded, the costs of the asset retirement obligation must be recorded as an addition to the carrying amount to the related asset. Over time, the liability is accreted to its present value and the addition to the carrying amount of the asset is depreciated over the asset’s useful life. Upon retirement of the asset, the group will settle the retirement obligation against the recorded balance of the liability. Any difference in the financial retirement obligation cost and the liability will result in either a gain or loss. On implementation of FAS 143, the group recorded a cumulative effect of accounting change of a loss of £0.6 million, net of tax.
In April 2002, the FASB issued FAS 145 ‘Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections’. The group adopted FAS 145 with effect from 1 April 2003, which had no impact on the group’s results and financial position under US GAAP. However, FAS 145 prohibits the classification of extraordinary items within the income statement and accordingly the costs of early debt repayment which were recorded as an extraordinary item in the year ended 31 March 2002 are no longer classified as an extraordinary item.
In April 2003, the FASB issued FAS 149 ‘Amendment of Statement 133 on Derivative Instruments and Hedging Activities’. FAS 149 amends and clarifies financial reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. This statement was effective for contracts entered into or modified after 30 June 2003 and had the effect of increasing the number of contracts to which mark-to-market accounting is applied.
In May 2003, the FASB issued FAS 150 ‘Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity’. This statement affects the accounting for certain financial instruments that, under previous guidance, issuers could account for as equity. The new statement requires that those instruments be classified as liabilities. Most of this statement was effective for financial instruments entered into or modified after 31 May 2003 and otherwise was effective for the group from 1 July 2003. This statement had no impact on the group’s results and financial position under US GAAP.
In May 2003, the FASB issued Emerging Issues Task Force (“EITF”) Issue 01-8 ‘Determining Whether an Arrangement Contains a Lease’. This Issue, which is an interpretation of FAS 13 ‘Accounting for leases’, specifies that an arrangement conveys the right to property, plant and equipment if the arrangement conveys to the purchaser the right to control the use of the underlying property, plant and equipment and sets out conditions for determining whether a right to control the use of such assets has been conveyed. Issue 01-8 applied to contracts entered into or modified on or after 1 July 2003. On implementation, this Issue had no impact on the group’s results and financial position under US GAAP.
In July 2003, the FASB issued EITF 03-11 ‘Reporting Gains and Losses on Derivative Instruments that Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes’. This Issue addresses whether realised gains and losses should be shown gross or net in the income statement for contracts that are not held for trading purposes but are derivatives subject to FAS 133. EITF 03-11 was effective from 1 January 2004. This Issue had no impact on the group’s net result or financial position under US GAAP, but has led to a reduction in US GAAP reported turnover of £979.8 million (2002/03: £660.6 million) with an equivalent reduction in cost of goods sold as a result of the netting approach adopted for contracts within the scope of the Issue.
In January 2004, the FASB issued FAS 132R, ‘Employers’ Disclosures about Pensions and Other Postretirement Benefits’. This statement changed the required disclosures for pension and other post-retirement benefit plan assets, obligations and net cost but did not impact the group’s results and financial position under US GAAP.
US GAAP Developments Applicable in the Future
In January 2003, the FASB issued ‘FASB Interpretation No. 46, Consolidation of Variable-Interest Entities, an interpretation of Accounting Research Bulletin No. 51’ (“FIN 46”), which requires existing unconsolidated variable-interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. FIN 46 was subsequently revised and became effective for the group on 1 April 2004. The group has considered the application of this standard to its operations and has completed an assessment of its impact. Following this review, the group identified one variable-interest entity which would be required to be consolidated as of 1 April 2004. However, as the entity did not agree to supply the information due to the lack of a contractual obligation to do so, the group is unable to consolidate this entity. Further details are provided in Note 34 to the Group Accounts.
In January and May 2004, the FASB issued FASB Staff Position No. 106-1 and FASB Staff Position No. 106-2 ‘Accounting and Disclosure Requirements Related to the
ScottishPower Annual Report and Accounts 2003/04 59
Financial Review
Medicare Prescription Drug, Improvement and Modernization Act of 2003’ (“FASB SP No. 106-1” and “FASB SP No. 106-2”). The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”) was signed into law in December 2003 and establishes a prescription drug benefit, as well as a federal subsidy to sponsors of retiree healthcare benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare’s prescription drug coverage. FASB SP No. 106-2 provides guidance on the accounting for the effects of the Medicare Act for employers that sponsor post-retirement healthcare plans that provide prescription drug benefits and requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. Under FASB SP No. 106-1, the group elected to defer accounting for the effects of the Medicare Act. This deferral remains in effect until the appropriate effective date of FASB SP No. 106-2. For entities that elected deferral and for which the impact is significant, FASB SP No. 106-2 is effective for the first interim or annual period beginning after 15 June 2004. For entities that will not recognise a significant impact, delayed recognition of the effects of the Medicare Act until the next regularly scheduled measurement date following issuance of FASB SP No. 106-2 is allowed. The group is still evaluating the impact of the Medicare Act. Accordingly, the group’s Accounts do not reflect the effects that may result from the Medicare Act.
International Financial Reporting Standards
In June 2002, the European Union (“EU”) adopted Regulations which require that the consolidated accounts of listed companies in the EU should, from 2005, be presented in accordance with adopted IFRS and IAS collectively referred to below as ‘IFRS’.
ScottishPower will be required to present its consolidated Accounts in accordance with IFRS for the financial year commencing 1 April 2005. The group’s Accounts will, from that date, no longer be prepared in accordance with UK GAAP. As an international business, the group is supportive of the moves to harmonise accounting standards.
The IASB, which is responsible for issuing IFRS, undertook that all new and revised standards applicable for 2005 would be issued by the end of March 2004. In reaching this deadline, the IASB has issued 21 new or revised standards since December 2003. Although any further standards issued by the IASB, will not be mandatory for the first year of IFRS implementation, the group may nevertheless choose to apply some or all of any such standards in its first year of IFRS implementation.
In order to facilitate the orderly transition to reporting in accordance with IFRS, the group has established an implementation project, with a mix of dedicated and ad hoc expert resource. An IFRS Steering Committee, chaired by the Finance Director has met on a monthly basis since October 2003. The role of the Steering Committee is to oversee all aspects of the group’s implementation project. Regular updates on the progress of the project are provided to the Audit Committee.
It is not possible at this time to be definitive as to the precise financial impact of the conversion to IFRS as:
| • | many of the standards have only recently been issued and their content is still being analysed; |
| • | further standards may be issued prior to the group’s implementation of IFRS which may be applied before their mandatory implementation date; |
| • | the EU’s adoption of specific IFRSs issued by the IASB remains uncertain. |
Despite these uncertainties, the group has assessed, at a high level, the potential impact of known and expected IFRS and has drawn the following preliminary conclusions:
| • | many of the IFRS requirements will have little or no impact on the group’s results and financial position; |
| • | key areas which are likely to have a potentially significant impact on the group’s results and financial position are: |
– Financial instruments
– Pensions and other post-retirement benefits
– Goodwill;
| • | other areas which are likely to have a moderate impact on the group’s results and financial position are: |
– Share-based payment
– Leases
– Post-balance sheet events.
Further details of those areas where there is a potentially significant impact on the group’s results and financial position are given below:
Financial Instruments
IAS 39 ‘Financial Instruments: Recognition and Measurement’ was revised by the IASB in December 2003 with further modifications in March 2004. This standard broadly requires a fair value approach to accounting for financial instruments, with mark-to-market gains and losses being reflected in the profit and loss account, unless certain onerous hedge accounting requirements are met. The definition of financial instruments within the standard is wide and is expected to include not only the group’s treasury financial instruments but also a number of the group’s energy contracts which have previously been accounted for on a cost basis. The group is currently analysing the requirements of this very complex standard and will review its operating and hedging strategies with a view to mitigating the potential volatility in reported results. Although any residual volatility will impact the group’s reported results, this will have no effect on the underlying cash flows payable in accordance with the contract terms. In addition, PacifiCorp has entered into a number of long-term energy contracts to meet its future retail load requirements and, due to the regulatory environment in which it operates, it is allowed to recover the underlying costs of these contracts through rates charged to customers. As a consequence, movements in market values of these contracts have no effect on the cash flows receivable from customers.
60 ScottishPower Annual Report and Accounts 2003/04
The requirements of IAS 39 will also impact on the group’s treasury operations, in particular, the group’s ability to hedge its US dollar earnings with derivative instruments. The group is currently reviewing its treasury-related portfolio of financial instruments in the light of the requirements of IAS 39.
Pensions and Other Post-Retirement Benefits
The IASB has issued proposals to amend its standard on pensions and other post-retirement benefits to allow similar accounting under IFRS to that which is required by FRS 17. The likely impact of IFRS with respect to pensions and other post-retirement benefits is that pension scheme surpluses and deficits and obligations in respect of other post-retirement benefits will be included as assets and liabilities in the balance sheet. This could result in significant volatility in the group’s net assets.
Goodwill
IFRS 3 ‘Business Combinations’ prohibits amortisation of goodwill and instead requires 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.
Over the 2004/05 financial year, the group plans to further develop its systems and processes in preparation for the implementation of IFRS. The group expects that it will be fully prepared for the transition to IFRS in 2005/06.
14 Off Balance Sheet Arrangements
The group has not entered into any transactions or arrangements which have given rise to off balance sheet obligations other than in respect of the following:
Operating Leases
The group has entered into various operating leases. In accordance with UK GAAP, future payments under these leases, amounting to £69.9 million at 31 March 2004 (2003: £50.5 million), are not recognised as liabilities in the group’s balance sheet.
Derivative Contracts
The group has entered into various energy-related and treasury derivative contracts, primarily for hedging purposes. In accordance with UK GAAP, the value of derivatives held for hedging purposes are only recognised when the hedged item is recognised. This contrasts with US GAAP which requires that derivatives, as defined in the relevant US accounting standards, are reflected as assets or liabilities at their market values at the balance sheet date. An analysis of the group’s derivatives, as defined under US GAAP, is set out in the Fair Value of Derivative Contracts section on page 55.
Guarantees
In the course of its ordinary business, the group has provided certain guarantees of its own performance. These guarantees are not expected to have a material impact on the group’s financial position.
In addition, in accordance with common practice, the group has provided guarantees of the performance of certain businesses and assets which have been disposed of. The amounts guaranteed under these arrangements are significant in absolute value but the probability of these guarantees crystallising and resulting in a material change in the group’s financial position is remote. The group has also entered into other arrangements in the normal course of business which may crystallise as a result of events other than the group’s non-performance of its contractual obligations. The probability of these guarantees giving rise to a material change in the group’s financial position is remote. Further details of these guarantees are provided in Note 34 to the Group Accounts.
15 UK GAAP to US GAAP Reconciliation
The group’s Accounts are prepared in accordance with UK GAAP which differs in significant respects from US GAAP. Reconciliations of profit and equity shareholders’ funds between UK GAAP and US GAAP are set out in Note 34 to the Group Accounts. Under US GAAP, the profit for the year ended 31 March 2004 was £742 million, before charging a cumulative adjustment for the effect of adopting FAS 143, net of tax, of £0.6 million, compared to a profit of £648 million in the previous year, before crediting the cumulative adjustment for the effect of adopting Derivatives Implementation Group guidance Revised C15 and C16, net of tax, of £141 million. Earnings per share under US GAAP, before the cumulative adjustment for FAS 143, were 40.57 pence per share compared to earnings per share, before the cumulative adjustment adjusted for Revised C15 and C16, of 35.16 pence per share in 2002/03. Earnings per share under US GAAP were 40.54 pence per share compared to earnings per share for the year ended 31 March 2003 of 42.81 pence. Equity shareholders’ funds under US GAAP amounted to £5,730 million at 31 March 2004 compared to £5,480 million at 31 March 2003.
This has been a year of strong financial performance for ScottishPower with increased operating profit and lower interest charges leading to higher pre-tax profit and earnings per share. The lower debt position has also contributed to a stronger balance sheet. Our policy to hedge dollar earnings to reduce the impact of currency volatility successfully mitigated the impact on earnings of the weaker dollar. Our earnings for the financial year to March 2005 will continue to benefit from our hedging programme.
| /s/ David Nish |
| David Nish, Finance Director |
| 25 May 2004 |
ScottishPower Annual Report and Accounts 2003/04 61
Board of Directors and Executive Team
Chairman
Charles Miller Smith (64) joined the Board as Deputy Chairman in August 1999 and was appointed Chairman in April 2000. Following a career with Unilever for some 30 years, during the last five of which he was Director of Finance and latterly of the Food Executive, he was appointed Chief Executive of ICI in 1995 and then served as Chairman from 1999 to 2001. He is an international adviser to Goldman Sachs, a member of the Board of the Indian company, ICICI One Source plc, and a member of the Ministry of Defence Management Board. He is also a Governor of the Henley Management College. During the year, he served on the committee chaired by Professor Laura Tyson of London Business School which considered, in the light of the recommendations of the Higgs Review, ways of broadening the pool of non-executive directors.
Non-Executive Directors
Euan Baird (66) joined the Board in January 2001. He served as Chairman and Chief Executive Officer of Schlumberger Limited from 1986 to 2003. He is now non-executive Chairman of Rolls-Royce plc and a non-executive director of Société Générale, Areva and the New York Stock Exchange. He is a trustee of Tocqueville Alexis Trust and Carnegie Institution of Washington, and a member of the Advisory Committee of Banque de France. His current term of office, subject to his re-election in 2004, will expire at the AGM in 2007.
Mair Barnes (59) joined the Board in April 1998. She is a non-executive director of GWR Group plc, Patientline plc and the South African company, Woolworths Holdings Limited. She is a member of the Department of Trade and Industry’s Strategy Board and the Services Group Board. She was previously Managing Director of Woolworths plc in the UK until 1994, and subsequently became Chairman of Vantios plc until 1998. She was also formerly a non-executive director of Abbey National plc, Littlewoods plc and George Wimpey plc. She will retire from the Board after the AGM in 2004.
Donald Brydon (59) joined the Board on 30 May 2003. Following a 20-year career with Barclays Group plc, he joined AXA Group in 1997 and is now Chairman of AXA Investment Managers. He is a non-executive director of Allied Domecq plc and of Smiths Group plc (where he is also Chairman designate). He is Chairman of the London Metal Exchange. He is Deputy Chairman of the Financial Services Practitioner Panel and Chairman of the Code Committee of the Panel on Takeovers and Mergers. His current term of office, following his election in 2003, will expire at the AGM in 2006.
Philip Carroll (66) first joined the Board in January 2002. He resigned his position on 15 May 2003 following his appointment, in connection with the reconstruction of post-war Iraq, as Chairman of the Advisory Board with oversight of the Iraqi Oil Ministry. Following completion of this assignment, he was re-appointed to the Board on 20 October 2003. He was formerly Chairman and Chief Executive Officer of Fluor Corporation, a California-based international engineering, construction and services company, until his retirement in February 2002. Previously, he was with Shell Oil for over 35 years, serving as President and Chief Executive Officer from 1993 to 1998. He is an honorary life member of the Board of the American Petroleum Institute and holds various posts with the James A Baker III Institute for Public Policy of Rice University and the University of Houston. His current term of office, subject to his election in 2004, will expire at the AGM in 2005.
Sir Peter Gregson GCB (67) joined the Board in December 1996 and is the company’s senior independent non-executive director and Chairman of the Remuneration Committee. He was formerly a career civil servant, having served latterly as Permanent Secretary of the Department of Energy from 1985 to 1989 and Permanent Secretary of the Department of Trade and Industry until his retirement in June 1996. He was previously Deputy Chairman of the Board of Companions of the Chartered Management Institute and a non-executive director of Woolwich plc. He will retire from the Board after the AGM in 2004.
Nolan Karras (59) joined the Board in November 1999. He continues as a non-executive director of PacifiCorp, having previously (until the merger in November 1999) served as Chairman of the PacifiCorp Personnel Committee. He is President of The Karras Company, Inc., and a Registered Principal for Raymond James Financial Services. He is Chief Executive Officer of Western Hay Company, Inc., and a non-executive director of Beneficial Life Insurance Company. He is Chairman of the Utah State Higher Education Board of Regents and a member of the board of Ogden-Weber Applied Technology College. He also served as a member of the Utah House of Representatives from 1981 to 1990, and as Speaker of the Utah House of Representatives from 1989 to 1990. His current term of office will expire at the AGM in 2006.
Nick Rose (46) joined the Board in February 2003; he is Chairman of the Audit Committee and is the Committee’s designated “financial expert”. He is Finance Director of Diageo plc, having been appointed to this position in July 1999. Previously he held senior finance positions with GrandMet and was latterly Finance Director of International Distillers & Vintners in 1996 and then of United Distillers & Vintners in 1997. He is also a director of Moët Hennessy. His current term of office will expire at the AGM in 2006.
62 ScottishPower Annual Report and Accounts 2003/04
Executive Directors
Ian Russell (51) is Chief Executive, having been appointed to this position in April 2001. He joined ScottishPower as Finance Director in April 1994, and became Deputy Chief Executive in November 1998. He is a member of the Institute of Chartered Accountants of Scotland, having trained with Thomson McLintock, and has held senior finance positions with HSBC. He serves on the Council of Edinburgh International Festival and the Scottish Council of the Prince’s Trust, and is leading a UK Government Commission investigating the development of a National Youth Volunteering Strategy.
David Nish (44) is Finance Director, having joined ScottishPower in September 1997 as Deputy Finance Director and then being appointed to the Board as Finance Director in December 1999. In this capacity, he also has responsibility at Board level for performance and risk management. He is a member of the Institute of Chartered Accountants of Scotland, the Scottish Council of the CBI, the UK Government’s Employer Task Force on Pensions, and the Accounting Standards Board’s Urgent Issues Task Force, and a non-executive director of The Royal Scottish National Orchestra. Prior to joining ScottishPower, he was a partner with Price Waterhouse. He has a BAcc from the University of Glasgow.
Charles Berry (52) is Executive Director UK, responsible in this capacity for the UK energy businesses of Generation, Energy Management and Supply. He joined ScottishPower in November 1991 and was appointed to the Board in April 1999. He is a member of the Board of the Energy Saving Trust. Prior to joining ScottishPower, he was Group Development Director of Norwest Holst, a subsidiary of Compagnie Générale des Eaux, and prior to that held management positions within subsidiaries of Pilkington plc. He holds a BSc (First Class Hons) in Electrical Engineering from the University of Glasgow and a Masters Degree in Management from the Massachusetts Institute of Technology.
Judi Johansen (45) is President and Chief Executive Officer of PacifiCorp; she was appointed to this position in June 2001 and joined the Board on 1 October 2003. She joined PacifiCorp as Executive Vice President of Regulation and External Affairs in December 2000, having held senior positions with the Bonneville Power Administration and Washington Water Power. She is a member of the Boards of the Portland Branch of the US Federal Reserve Bank of San Francisco, the Port of Portland, The Haven Project for Disadvantaged Youth, the Oregon Business Council and Northwestern School of Law at Lewis & Clark College. She has a bachelor’s degree in political science from Colorado State University and a law degree from Northwestern School of Law at Lewis & Clark College in Portland, Oregon, and is a member of the Oregon and Washington State Bar Associations.
Simon Lowth (42) is Director, Corporate Strategy and Development, having been appointed to the Board in this position on 1 September 2003. He is responsible in this role for leading the formulation, presentation and delivery of corporate strategy. He was formerly a Director with McKinsey and Company, leading its UK industrial practice, serving clients in the energy and utilities, manufacturing and transport sectors. He holds an MA in Engineering from Cambridge University and an MBA from London Business School.
Executive Team
The Executive Team is constituted as a committee of the Board and includes not only the Executive Directors of the Board but also the following key Executives and Officers from the group. For US reporting purposes the members of the Executive Team are regarded as officers of the company.
Dominic Fry (44) joined ScottishPower in September 2000 as Group Director, Corporate Communications. He is responsible for investor and media relations, communications with employees, corporate social responsibility and management of the group’s overall reputation. He has held appointments as Communications Director with J Sainsbury plc and Eurotunnel plc. He chairs the Trading Board of the Glasgow Science Centre and is a communications adviser to the Royal Shakespeare Company and Business in the Community. He is also a director of Scottish Business in the Community. He was educated at the Université Paul Valéry III in Montpellier and the University of North Carolina.
Terry Hudgens (49) was appointed Chief Executive Officer of ScottishPower’s competitive US energy business, PPM, in May 2001 and joined the Executive Team in December 2001. He joined PacifiCorp as Senior Vice President of Power Supply in April 2000, having previously spent 25 years with Texaco, Inc. He was formerly President of Texaco Natural Gas and served as Texaco’s senior representative and elected officer in the Natural Gas Supply Association. He is a member of the Board of Trustees of The Nature Conservancy in Oregon. He has a bachelor’s degree in civil engineering from the University of Houston.
Ronnie Mercer (60) was appointed Group Director, Infrastructure in April 2001 and is responsible in this role for the UK wires businesses. He joined the ScottishPower Generation Business in 1994 and was appointed Generation Director in 1996 and then Managing Director of Southern Water in 1998. Previous career positions include Scottish Director and Managing Director roles in British Steel. He was educated at Paisley College of Technology.
Andrew Mitchell (52) was appointed Group Company Secretary in July 1993 and is responsible in this role for Board and shareholder services, corporate governance and compliance, and
ScottishPower Annual Report and Accounts 2003/04 63
Board of Directors and Executive Team
group security. He also serves as Chairman of the trustees of the group’s UK pension schemes and as the company’s e7 representative. Prior to joining ScottishPower, he held a number of company secretarial appointments, latterly as Company Secretary of The Laird Group plc and then Stakis plc, now part of the Hilton Group. He is a graduate in law from the University of Edinburgh (LLB Hons) and the London School of Economics (LLM) and is a member of the Institute of Chartered Secretaries and Administrators.
Michael Pittman (51) was appointed Group Director, Human Resources in November 2001. He has groupwide responsibility for human resources, leading the focus on talent management, one of the group’s main strategic thrusts. He joined PacifiCorp in December 1979 and was appointed to the PacifiCorp Board in May 2000. He chairs the PacifiCorp Foundation for Learning Board and is involved in numerous civic activities, including chairing the Board of Directors for the Oregon Public Employees Retirement System. He has held several positions within PacifiCorp, including safety and health, risk management and operations. He holds an advanced degree in environmental health from the University of Washington.
James Stanley (49) was appointed Group Director, Commercial and Legal in March 1996. He is responsible in this role for legal compliance and reporting together with the provision of all legal, commercial and associated services throughout the group and particularly the negotiation, structuring and delivery of M&A and similar projects. In his early career he specialised in commercial litigation in private practice. In 1986 he moved to the Trafalgar House Group and subsequently became both Commercial Director of John Brown plc and General Counsel to the Global Engineering Division of the Group. He is a graduate in law from Nottingham University and the College of Law in Chester where he qualified as a solicitor in 1980.
Members of the Nomination Committee
Charles Miller Smith, Chairman
Mair Barnes
Sir Peter Gregson
Nolan Karras
Ian Russell
Members of the Remuneration Committee
Sir Peter Gregson, Chairman
Euan Baird
Mair Barnes
Donald Brydon
Philip Carroll
Nolan Karras
Members of the Audit Committee
Nick Rose, Chairman
Donald Brydon
Philip Carroll
Sir Peter Gregson
Nolan Karras
Board and Executive Team changes
Ewen Macpherson retired from the Board following the conclusion of last year’s AGM on 25 July 2003. Donald Brydon was appointed to the Board on 30 May 2003; his appointment was confirmed by his election at the AGM in 2003. Philip Carroll resigned from the Board on 15 May 2003 following his appointment, in connection with the reconstruction of post-war Iraq, as Chairman of the Advisory Board with oversight of the Iraqi Oil Ministry; following completion of this assignment, he was re-appointed to the Board on 20 October 2003. Simon Lowth and Judi Johansen were appointed to the Board on 1 September 2003 and 1 October 2003 respectively.
The company has appointed two new non-executive directors who will join the Board with effect from 1 June 2004.
Vicky Bailey (52) who is based in Washington DC, is a former Assistant Secretary for Policy and International Affairs at the US Department of Energy and ex-member of the Federal Energy Regulatory Commission (“FERC”). She has also served as an Indiana state regulator.
Nancy Wilgenbusch (56) is a distinguished community administrator and President of Marylhurst University in Portland, Oregon. She also serves on the Regional Advisory Board of PacifiCorp.
In accordance with the Articles of Association, Vicky Bailey, Philip Carroll, Judi Johansen, Simon Lowth and Nancy Wilgenbusch will retire from office at the Annual General Meeting and, being eligible, offer themselves for election. In addition, Euan Baird, Mair Barnes, Sir Peter Gregson and Ian Russell retire by rotation at the Annual General Meeting. Euan Baird and Ian Russell, being eligible, offer themselves for re-election. Mair Barnes and Sir Peter Gregson will retire from the Board and accordingly do not seek re-election. Ian Russell has a service contract terminable by either party upon twelve months’ notice.
64 ScottishPower Annual Report and Accounts 2003/04
1 Corporate Governance Statement
Scottish Power plc is committed to the highest standards of corporate governance. This statement, together with the Remuneration Report of the Directors, set out on pages 72 to 83, describes how, in respect of the financial year ended 31 March 2004, the company has applied the principles of good corporate governance and has complied with the provisions set out in Section 1 of the Combined Code in the UK and with the Sarbanes-Oxley Act 2002 and associated rules (to the extent they apply to the company) in the US.
The company has reviewed the additional requirements which will apply with effect from 1 April 2004 as a result of the changes to the Combined Code arising from the Higgs Report and the guidance for audit committees contained in the Smith Report, and has indicated in this report the extent to which it already complies with these obligations and the actions which have been taken to address the few remaining areas introduced by the new Code. The company has also taken account of the recent changes to the listing rules of the New York Stock Exchange, as they apply to foreign issuers, and other developments such as the issue by the National Association of Pension Funds of its revised Corporate Governance Policy.
The Board comprises the Chairman, five executive directors and seven non-executive directors. All of the non-executive directors are considered to be independent and Sir Peter Gregson is the senior independent director. Biographies of Board members, giving details of their experience and other main commitments, are set out on pages 62 and 63. The wide ranging experience and backgrounds of the non-executive directors ensure that they can debate and constructively challenge management in relation to both the development of strategy and performance against the goals set by the Board. Attendance of Board members at Board and Committee meetings is set out in Table 42.
Table 42 – Board and Committee attendance during the year ended 31 March 2004
| Charles Miller Smith |
Euan Baird1 (R) |
Mair Barnes (N, R) |
Donald Brydon2 (R, A) |
Philip Carroll3 (R, A) |
Sir Peter Gregson (N, R*, A) |
Nolan Karras (N, R, A) |
Ewen Macpherson4 (R, A) |
Nick Rose (A*) |
Ian Russell (N) |
Charles Berry |
Judi Johansen5 |
Simon Lowth6 |
David Nish | |||||||||||||||
| Board (12 meetings) |
12 | 7 | 12 | 7 | 6 | 12 | 12 | 4 | 10 | 12 | 12 | 6 | 7 | 12 | ||||||||||||||
| Nomination Committee (8 meetings) |
8 | 8 | 8 | 7 | 8 | |||||||||||||||||||||||
| Remuneration Committee (7 meetings) |
4 | 7 | 2 | 3 | 7 | 6 | 3 | |||||||||||||||||||||
| Audit Committee (7 meetings) |
2 | 3 | 7 | 7 | 4 | 7 |
N – Nomination Committee
R – Remuneration Committee
A – Audit Committee
| * | Committee Chairman |
| 1 | Euan Baird has been absent from the Board and Remuneration Committee since December 2003 due to ill health. |
| 2 | Donald Brydon was appointed to the Board in May 2003, and to the Remuneration and Audit Committees in October 2003. |
| 3 | Philip Carroll resigned from the Board and Audit Committee in May 2003. He was re-appointed to the Board and Audit Committee, and was appointed to the Remuneration Committee, in October 2003. |
| 4 | Ewen Macpherson retired from the Board, and from the Remuneration and Audit Committees, in July 2003. |
| 5 | Judi Johansen was appointed to the Board in October 2003. |
| 6 | Simon Lowth was appointed to the Board in September 2003. |
Non-executive directors are appointed for a specified term of three years and re-appointment is not automatic. It is company policy that, other than in exceptional circumstances, non-executive directors should serve no more than two three-year terms. In Sir Peter Gregson’s case, it was agreed by the Board at the end of his two terms that he should serve for a further year to facilitate succession planning and he will stand down as a director at the conclusion of the 2004 AGM. Directors also stand for re-election by the shareholders at the first annual general meeting following their appointment and subsequently at least every three years. The report from the Nomination Committee contained in this report explains the process for selection of directors and succession planning.
There is a well-established division of authority and responsibility at the most senior level within the company through the separation of the roles of Chairman and Chief Executive. The senior independent director is available to shareholders for concerns which cannot be resolved by contact with the Chairman or Chief Executive.
Directors and officers of the company and its subsidiaries have the benefit of a directors’ and officers’ liability insurance policy. All directors can take independent legal advice at the company’s expense in furtherance of their duties.
ScottishPower Annual Report and Accounts 2003/04 65
Corporate Governance
The Board meets on a regular basis twelve times a year, and otherwise as required. Of the twelve normal meetings, six are held at company locations in the UK and US, and the remaining six are held by telephone conference. For a number of years the company has included within this meeting programme provision for the non-executive directors to meet annually in the absence of the Chairman and/or executive directors.
In January 2004 the Board approved a revised schedule of matters reserved to it for decision. This schedule is intended to ensure that the Board retains full control over strategy, investment and capital expenditure, and limits the decisions which can be taken by management in the areas of governance, strategic and financial management and reporting, capital structure, corporate actions, mergers and acquisitions, energy management, contracts and other commitments, litigation and regulatory proceedings, remuneration and share plans. Where authority is delegated to management it is on a structured basis, ensuring that proper management oversight exists at the appropriate level. Within management, the Executive Team, which meets at least twice a month either physically or by telephone conference, ensures executive focus on groupwide performance and risk management, while each of the four divisions holds monthly board meetings involving the Chief Executive and Finance Director as well as senior divisional management.
Board meetings involve reviews of financial and business performance against the plan approved by the Board and risk management, both at a group level and also for each of the four business divisions, on a month by month basis. On a rotating basis, the Board receives presentations from each of the divisions and other key functions enabling it to explore specific issues and developments in more detail. Any matter requiring a decision by the Board will be supported by a paper analysing all relevant aspects of the proposal – for example, in the case of capital expenditure, expected returns and a comparison to the investment hurdles set by the Board as well as potential risks and proposed management action.
The Company Secretary is responsible for ensuring that all Board procedures are observed and for advising the Board on corporate governance matters.
The Board is supported by a number of committees: as well as the Nomination, Remuneration and Audit Committees, the Board has also established a Group Finance Committee, chaired by Philip Carroll and comprising both executive and non-executive directors, which allows for more detailed scrutiny of financing issues than would be possible within the confines of regular Board meetings. It has authority to approve financing transactions within the strategy set by the Board.
Reports from the Nomination and Audit Committees are contained within this Report, in Sections 4 and 8 respectively. The activities of the Remuneration Committee are described within the Remuneration Report on pages 72 to 83.
4 Report from Nomination Committee
Charles Miller Smith, the Chairman of the company, is the Chairman of the Committee. The other members of the Committee throughout the year were Mair Barnes, Sir Peter Gregson and Nolan Karras, all of whom are independent directors, and Ian Russell, the Chief Executive. The majority of the members of the Committee are therefore independent.
66 ScottishPower Annual Report and Accounts 2003/04
Details of their qualifications and experience are set out on pages 62 and 63. Andrew Mitchell, Company Secretary, acts as secretary to the Committee.
The Committee has written terms of reference. Its principal role is to:
| • | regularly review the structure, size and composition (including the skills, knowledge and experience) required by the Board; |
| • | give full consideration to succession planning for directors, taking into account the challenges and opportunities facing the company and what skills and expertise are needed on the Board in the future; |
| • | identify and nominate, for the approval of the Board, candidates to fill Board vacancies as and when they arise; |
| • | consider and approve the remit and responsibilities of the executive directors; |
| • | keep under review legal and regulatory developments in relation to corporate governance and consider changes to the company’s policy and practices to address such developments. |
The Committee has developed a robust process for the selection and recruitment of directors. Following a review of the Board’s size, composition and diversity, the Committee determines the selection criteria and the role specification. External selection consultants are retained to conduct searches. The Committee reviews the profiles of the candidates and interviews are carried out. The Committee then makes its recommendations to the Board for approval.
During the year ended 31 March 2004, the Committee met on eight occasions. In addition to identifying and nominating candidates as directors for approval by the Board, the Committee reviewed the size, composition and diversity of the Board, Executive Team performance and potential, career development, and corporate governance developments. In the light of the revised Combined Code, the Committee examined the relationship with shareholders, directors’ training and development and Board performance evaluation.
5 Relationship with Shareholders
The company’s Investor Relations department communicates with its institutional investors through analysts’ briefings and extensive investor roadshows in the UK, US and Europe, as well as timely stock exchange announcements, meetings with management and site visits. The Board, and in particular non-executive directors, are kept informed of investors’ views in the main through distribution of analysts’ and brokers’ briefings. Both the Chairman and, if appropriate, the senior independent director are available in the event of shareholder concerns which cannot be addressed through management. At the time of appointment of new non-executive directors they are available to meet with shareholders on request.
Broader shareholder communication takes place through the ScottishPower website, www.scottishpower.com, which contains recent company announcements and other useful information, including the terms of reference of the Nomination, Remuneration and Audit Committees, and also through the Annual Report and Accounts and Annual General Meeting. All directors attend the AGM, and shareholders have the opportunity to hear presentations on the company’s financial and business performance as well as to question the Board on its stewardship of the company.
6 Directors’ Training and Development
Newly-appointed directors undergo a structured induction programme, to ensure that they have the necessary knowledge and understanding of the company and its activities. Starting at the time of their appointment, and continuing on an incremental basis over the first six months, they undertake briefing sessions on corporate governance, strategy, stakeholder issues, finance and risk management and HR strategy, as well as meetings and site visits to business locations both in the UK and US. Each director’s individual experience and background is taken into account in developing a programme tailored to their own requirements.
Continuing development is provided through briefing sessions in the course of regular Board meetings, covering business-specific and broader regulatory issues. Directors also receive a monthly in-house newsletter highlighting topical governance and related developments of relevance to ScottishPower.
7 Board Performance Evaluation
In 2003 the company undertook an independent evaluation of the performance of the Board, undertaken by the Institute of Chartered Secretaries and Administrators (“ICSA”), involving private interviews with directors. The outcome of the evaluation, including specific recommendations, was regarded as very positive. The results of this evaluation were reviewed, again by the ICSA, through a follow-up survey undertaken in early 2004. The follow-up survey was again considered to be very positive with improvements noted in a number of areas. To comply with the requirements of the revised Combined Code, an evaluation of the performance of the Nomination, Remuneration and Audit Committees and of individual directors will be undertaken during the year ending 31 March 2005.
Nick Rose is the Chairman of the Committee. He replaced Ewen Macpherson, the previous Committee Chairman, who retired from that position upon his retirement from the Board on 25 July 2003. He has also been identified as
ScottishPower Annual Report and Accounts 2003/04 67
Corporate Governance
the “audit committee financial expert” for Scottish Power plc. The other members of the Committee, all of whom are independent directors, are Philip Carroll (resigned from the Committee on 15 May 2003 and re-appointed to the Committee on 20 October 2003), Donald Brydon (appointed to the Committee on 24 October 2003), Sir Peter Gregson and Nolan Karras. Details of their qualifications and experience are set out on pages 62 and 63. Andrew Mitchell, Company Secretary, acts as secretary to the Committee.
The Committee has written terms of reference. Its principal role is to review:
| • | the effectiveness of the system of internal control and consider reports from both internal and external auditors on key risks facing the group and controls over these risks; |
| • | the company’s financial statements, including accounting policies, compliance with legal and regulatory requirements, judgmental issues and the findings of the external auditors; |
| • | the activities and effectiveness of the internal audit function; |
| • | the relationship with the external auditors, including the engagement of auditors, the audit scope and approach, fees and performance, and policy on provision of non-audit services by the external auditors and recruitment of former external auditors by the company; |
| • | compliance with legal and regulatory requirements; |
| • | litigation and claims affecting the group. |
Meetings of the Committee are normally attended by the Chief Executive, the Finance Director, the Director, Group Internal Audit and representatives of the external auditors. However, the Committee holds regular private sessions to meet separately with senior management, representatives of internal audit and the external auditors, and external counsel.
During the year ended 31 March 2004 the Committee met on seven occasions. In addition to reviewing the company’s quarterly results before publication and receiving reports on audits undertaken by internal audit, the Committee received presentations from management in each of the four divisions reviewing risks and management actions in those areas and progress reports on actions being taken by the company to address new legal and regulatory developments, including the introduction of International Financial Reporting Standards and Section 404 of the Sarbanes-Oxley Act 2002.
The directors of ScottishPower have overall responsibility for establishing and maintaining an adequate system of internal controls and for reviewing the effectiveness of the system. The system of internal control is designed to manage rather than eliminate risk. In pursuing these objectives, internal control can only provide reasonable and not absolute assurance against material misstatement or loss.
The Executive Team is responsible for implementing the risk management strategy; ensuring that an appropriate risk management framework is operating effectively across the group; embedding a risk culture throughout the group; and providing the Board and the Audit Committee with a consolidated view of the risk profile of the company, identifying any major exposures and mitigating actions.
The risk management framework and internal control system across the group, which is subject to continuous development, provides the basis on which the company has complied with the Combined Code provisions on internal control.
The company is committed to ensuring that a proper control environment is maintained. There is a commitment to competence and integrity and to the communication of ethical values and control consciousness to managers and employees. Employees are required to adhere to the company’s Code of Conduct and Disciplinary Rules. Furthermore, in compliance with the Sarbanes-Oxley Act 2002, the company has adopted a Code of Ethics for the Chief Executive, Finance Director and principal accounting officers. Human resources policies underpin that commitment by a focus on enhancing job skills and promoting high standards of probity among staff. In addition, the appropriate organisational structure has been developed within which to control the businesses and to delegate authority and accountability, having regard to acceptable levels of risk.
The company has developed a fraud policy and implemented procedures to ensure that all incidences of fraud are appropriately investigated and reported.
A Disclosure Committee is in place to ensure effective disclosure controls are operating around the production of key published financial statements and to provide assurance to the Chief Executive and Finance Director that they may sign their formal certification to the Securities and Exchange Commission (“SEC”) in accordance with Section 302 of the Sarbanes-Oxley Act 2002.
11 Identification and Evaluation of Risks and Control Objectives
The company’s strategy is to follow an appropriate risk policy, which effectively manages exposures related to the achievement of business objectives.
Each business identifies and assesses the key business risks associated with the achievement of its strategic objectives. Any key actions needed to further enhance the control environment are identified along with the person responsible for the management of the specific risk. Each month a detailed review of the key risks, controls and action plans within each of the businesses takes place and a Risk Report is produced for review and challenge by the business boards at their monthly
68 ScottishPower Annual Report and Accounts 2003/04
meetings. This is a key tool in ensuring the active management of risk across the organisation.
Business controls managers have been appointed within each of the businesses to help ensure that the risk management and internal controls system is consistently adopted, updated and embedded into the business processes.
The corporate centre also considers those risks to the group’s strategic objectives that may not be identified and managed at a business level.
The Board and Executive Team on a monthly basis receive the groupwide Risk Report together with supporting documentation for review. This report highlights the most significant risks across the group and the actions being taken to mitigate them, and also identifies the individuals responsible for the management of these risks. The information being supplied to the Board and Executive Team is continually being developed to include quantitative measures such as sensitivity analyses and Value-at-Risk calculations for issues reported in the Group Energy Risk Report.
The use of a well-defined risk management methodology across all businesses allows a consistent and coordinated approach to risk reporting for review by the Board, which also receives regular reports on these matters from the Audit Committee, to enable the directors to review the effectiveness of the system of internal control on a regular basis.
A key element and requirement of the risk evaluation process is that a written certificate is provided quarterly by all members of the Executive Team, confirming that they have reviewed the effectiveness during the period of the system of internal control under their responsibility.
A Group Energy Risk Committee (“GERC”) has been established to assist the Executive Team in ensuring that there is an appropriate risk and control governance framework in place over energy activities. The GERC meets monthly and the key responsibility of this group is to make suitable recommendations to the Executive Team on energy-related risk management issues. In addition, the Group Energy Risk Director, with other members of the GERC, continues to enhance business processes and systems to ensure that all risks pertaining to the energy management businesses are understood, quantified, managed and reported on a consistent basis across the group.
The GERC also provides advice and guidance to the businesses on interpretation and execution of the Group Energy Risk Policy.
Substantial capital investment proposals are reviewed by the Group Investment Committee (“GIC”), chaired by the Finance Director, to ensure that they are in line with the group’s strategy, achieve the required rate of return, comply with legal requirements and commercial practice, and are supported by robust financial analysis. The role of the GIC, acting on behalf of the Executive Team, is to review the group’s capital programme, monthly and quarterly capital expenditure and capital budgeting process, and to monitor the post-investment appraisal process. In particular the GIC reviews all business acquisitions and disposals and new business ventures.
14 Monitoring and Corrective Action
The Executive Team reviews monthly the key risks facing the group and the controls and monitoring procedures for these. Operation of the group’s control and monitoring procedures is reviewed and tested by the group’s Internal Audit function under the supervision of the Director, Group Internal Audit, reporting to the Finance Director and with access to the Chairman of the Audit Committee. Internal Audit reports and recommendations on the group’s procedures are reviewed regularly by the Audit Committee. The external auditors also provide reports to the Audit Committee on matters in relation to the group’s internal financial control procedures identified during the course of their audit. The Audit Committee also receives regular reports on the continued development, implementation and evaluation of the risk management and internal control system.
The Audit Committee and the firm of external auditors have safeguards to avoid the possibility that the auditors’ objectivity and independence could be compromised. These safeguards include adoption by the Committee of a policy regarding pre-approval of audit and permitted non-statutory audit services provided by the external auditors and a policy on the hiring of external audit staff.
Where the work to be undertaken is of a nature that is generally considered reasonable to be completed by the external auditors for sound commercial and practical reasons, including confidentiality, the conduct of such work will be permissible provided that it has been pre-approved by the Audit Committee. Examples of pre-approved services include the completion of regulatory audits, provision of taxation and regulatory advice, reporting in relation to SEC and UK Listing Authority requirements and the completion of certain financial due diligence work. Under the policy, any work performed in excess of a pre-defined limit must also be approved by the Finance Director and the Chairman of the Audit Committee.
ScottishPower Annual Report and Accounts 2003/04 69
Fees paid to the external auditors during the year ended 31 March 2004 (with equivalent information for the year ended 31 March 2003) are shown in Table 43 below:
Corporate Governance
Table 43 – Auditors’ remuneration
| 2004 |
2003 | |||
| £m | £m | |||
| Audit services |
||||
| – statutory audit |
1.5 | 1.5 | ||
| – audit-related regulatory reporting |
0.4 | 0.6 | ||
| Further assurance services |
0.7 | 0.7 | ||
| Tax services |
||||
| – compliance services |
1.6 | 1.6 | ||
| – advisory services |
0.8 | 3.2 | ||
| Other services |
– | 0.3 | ||
| Total UK and US audit and non-audit fees paid to auditors |
5.0 | 7.9 | ||
All of these fees were either specifically approved by the Audit Committee or were subject to the pre-approval procedure described above.
16 Evaluation of Disclosure Controls and Procedures (Sarbanes-Oxley Act 2002)
The Chief Executive and the Finance Director have evaluated the effectiveness of the group’s disclosure controls and procedures as at the end of the period covered by this report. Based on this evaluation, the Chief Executive and Finance Director concluded that the disclosure controls and procedures are effective.
There has been no change to the group’s internal controls that has materially affected, or is reasonably likely to materially affect, these controls over financial reporting during the period covered by this report.
17 Social, Environmental and Ethical Matters
The Board receives monthly operational reports which include consideration of relevant developments across the group in social, environmental and ethical (“SEE”) matters. This enables the Board to take regular account of the strategic significance of SEE matters to the group, and to consider the risks and opportunities arising from these issues that may have an impact on the group’s short- and long-term value. SEE matters are also included in the induction and development programme for directors.
In terms of risk identification and management, SEE matters are included in the overall risk and control framework and in the Risk Report which is reviewed on a monthly basis by the Board and Executive Team. The company also employs management tools such as balanced scorecards to measure progress against key strategic priorities and has developed an International Leadership Model which integrates values with performance throughout the business.
Further information regarding SEE matters can be found in the Business Review section of this Report. In addition, the company publishes separately an Environmental and Social Impact Report, which includes information on the company’s SEE policies and practices and internal governance structures, and individual Environmental, Workplace, Marketplace and Community Performance Reports which will appear on the company’s website. The Environmental and Social Impact Report and the Performance Reports are verified and independently assured by csr network, a corporate social responsibility consultancy firm.
18 Political Donations and Expenditure
ScottishPower is a politically neutral organisation but is required to comply with the Political Parties, Elections and Referendums Act 2000. This legislation defines political “donations” and “expenditure” in wider terms than would be commonly understood by these phrases. The definitions include expenditure which the Board believes it is in the interests of the company to incur. The Act also requires companies to obtain prior shareholder approval of this expenditure; at the Annual General Meeting in 2003 the company obtained authorisation up to a maximum amount of £100,000.
During the financial year ended 31 March 2004, the company paid a total of £13,950 for activities which may be regarded as falling within the terms of the Act. The recipients of these payments were:
| • | Scottish Labour Party £8,500 |
| • | Scottish Conservative and Unionist Party £2,000 |
| • | Scottish Liberal Democrats £1,950 |
| • | Scottish National Party £1,500 |
These activities comprised the sponsorship of briefings, receptions and fringe meetings at party conferences and attendance at party events. These occasions present an important opportunity for the company to represent its views on a non-partisan basis to politicians from across the political spectrum. The payments do not indicate support, and are not intended to influence support, for any particular political party.
It should be noted that these activities do not contravene the restrictions on political contributions under the US Public Utility Holding Company Act of 1935, to which the company is subject.
70 ScottishPower Annual Report and Accounts 2003/04
The New York Stock Exchange (“NYSE”) has recently issued revised corporate governance rules for its listed companies. These are mandatory for US incorporated companies whose shares are listed on NYSE, but foreign issuers such as Scottish Power plc are exempt from a number of these requirements and may adopt different practices that reflect home country practice. The company has reviewed its compliance with the new rules as they apply to US domestic companies and has determined that, with the exception of two specific areas, it will comply fully with the new NYSE corporate governance rules, which are broadly comparable to the requirements of the revised Combined Code. The two areas where the company will not comply with the NYSE rules are:
Composition of the Nomination Committee – in line with UK corporate governance practice, the Nomination Committee comprises a majority of independent non-executive directors, but does also include both the Chairman and Chief Executive. The NYSE rules would require all members of the Committee to be independent.
Adoption of Corporate Governance principles – UK listed companies are required either to comply with the Combined Code or explain why they have not done so. The company complies with the existing Combined Code, and has taken the necessary action to ensure compliance with the revised Code. The Combined Code in effect provides a set of corporate governance principles for the company addressing all of the corporate governance guidelines described in the NYSE rules, and accordingly the company does not believe that additional company-specific principles are necessary. Any decision to depart from the provisions of the Combined Code would require to be approved by the Board and disclosed to shareholders in the next Annual Report and Accounts.
ScottishPower Annual Report and Accounts 2003/04 71
Remuneration Report of the Directors
Remuneration Report of the Directors
| 1 | Consideration of Remuneration Matters by the Directors | |||
| 2 | Statement of Remuneration Policy | |||
| 3 | Elements of the Remuneration Package 2003/04 |
1 Consideration of Remuneration Matters by the Directors
The ScottishPower Board is responsible for determining the remuneration policy for the ScottishPower group. The Remuneration Committee, with delegated authority from the Board, determines the detail of remuneration arrangements for the Executive Team, including the executive directors, and reviews proposals in respect of other senior executives. The relationship between the Board and the Committee is based on formal Terms of Reference, which are regularly reviewed to ensure that they reflect best practice.
The Remuneration Committee consists solely of independent non-executive directors. Its members are Sir Peter Gregson (Chairman), Euan Baird, Mair Barnes, Donald Brydon (appointed to the Committee on 24 October 2003), Philip Carroll (appointed to the Committee on 24 October 2003) and Nolan Karras. Ewen Macpherson was a member of the Committee until his retirement from the Board on 25 July 2003. These members have no personal financial interest, other than as shareholders, in the matters considered by the Committee. Details of the payments made to all non-executive directors are set out in Table 44 (page 79).
The Chairman of the company, Charles Miller Smith, and the Chief Executive, Ian Russell, are invited to attend meetings and may provide guidance on the impact of remuneration policy and advise, as appropriate, on the performance of senior executives. They are not present during any discussion of their own remuneration. The Terms of Reference contain conflict of interest provisions to ensure that no directors are involved in any decision relating to their own remuneration.
The Committee is able to draw on advice from independent remuneration consultants and internal expertise. Towers, Perrin, Forster & Crosby, Inc., (“Towers Perrin”) act as remuneration consultant and independent advisor to the Committee. Towers Perrin’s appointment by the Committee followed a competitive tendering exercise. Towers Perrin also provides remuneration and other human resources consultancy services directly to some ScottishPower companies within parameters established by the Committee. Company executives whom the Committee may consult include the Group Company Secretary, Andrew Mitchell (who acts as Secretary to the Committee), the Group Director, Human Resources, Michael Pittman, the Director Group Leadership Development and Reward, Sandy Begbie, and the Head of Group Reward, Nigel Johnson. The Terms of Reference empower the Committee to avail itself of external legal and professional advice at the expense of the company.
The Committee met on seven occasions during the year ended 31 March 2004.
During the year, the Board accepted all of the recommendations from the Committee without significant amendment.
2 Statement of Remuneration Policy
Philosophy and Policy
ScottishPower seeks to ensure that remuneration and incentive schemes are in line with best practice, provide a strong link to individual and company performance and promote a community of interest between employees and shareholders.
72 ScottishPower Annual Report and Accounts 2003/04
Rewards for executives and directors are designed to attract and retain individuals of high quality, who have the requisite skills and are incentivised to achieve levels of performance which exceed that of competitor companies. As such, remuneration packages must be market-competitive and capable of rewarding exceptional performance. All senior management remuneration packages are set according to a mid-market position, with packages above the mid-market level provided only where supported by demonstrably superior personal performance. Remuneration packages are developed to reflect the prevailing market practice in each business environment.
Annual bonus arrangements have been structured so that stretching targets are based on corporate, business unit and individual performance.
The company operates a Personal Shareholding Policy (“PSP”), requiring executives and key senior managers to build up and retain a shareholding in the company in proportion to their annual salaries. These proportions are three times base salary for the Chief Executive and two times base salary for other executive directors. The Committee expects PSP participants to have accumulated their respective shareholding targets within eight years of the introduction of the Policy, that is by the end of May 2008, or eight years after the first award under any discretionary share plan for external appointees to the Board. The Committee reviewed this policy during the year and will continue to do so to ensure that it is in line with evolving best practice and in the interests of shareholders.
In setting remuneration levels, the Committee commissions an independent evaluation of the roles of the Executive Team, and also of the next levels of management within the company. The Committee takes independent advice from Towers Perrin on market-level remuneration, based on comparisons with other companies of similar size and complexity, including the major utility companies, with which the company competes for executive talent.
The Committee recognises the importance of linking rewards to business and personal performance and believes that the arrangements detailed below provide an appropriate focus on performance and balance between short- and long-term incentives. At target level, base salary is expected to deliver around 48% of total reward excluding benefits and pension. The annual bonus plan and long-term incentive arrangements are expected to provide 52% of total reward for the achievement of stretching target level business and personal performance objectives. Higher proportions of performance based reward are available for the delivery of exceptional personal and business performance resulting in enhanced shareholder value.
The Committee constantly monitors market practice in order to remain competitive, to ensure that reward policy supports company strategy and to reflect good corporate governance practice. As outlined below under the section entitled ‘Future Incentive Strategy’ the Committee has implemented changes to ScottishPower’s incentive strategy in order to help deliver enhanced shareholder returns. At this time, no other substantial changes to the company’s policies with regard to directors’ remuneration are envisaged over the next year and in subsequent years. However, the Committee may develop policy and, should it determine any changes to be appropriate, will report such changes to shareholders through established channels of consultation and reporting. For example, the Committee and the Board will consider carefully the impact of the Government’s reform of the pensions taxation environment and may amend executive pensions policy accordingly.
3 Elements of the Remuneration Package 2003/04
Base Salaries
The Committee sets base salaries for the Executive Team by reference to individual performance through a formal appraisal system applied to all management employees, and to external market data, reflecting similar roles in comparable companies. Account is also taken of salary increases and employment conditions across the company.
Annual Performance-Related Bonus
Executive directors and senior management participate in the company’s performance-related annual incentive plans. Any payments to UK executives under the plans are non-pensionable and are determined by the Committee following assessment against stretching pre-determined targets. In line with US market practice, a proportion of bonus paid to US senior executives, including Judi Johansen the CEO of PacifiCorp, is pensionable.
The 2003/04 plan for executive directors provided a maximum incentive opportunity of 75% of salary. For the Chief Executive, half is determined by the company’s performance, with the balance linked to the achievement of key personal, strategic and behavioural objectives, both short-term and long-term. For the other four executive directors, one-third is determined by the company’s performance, one-third is based on the performance of the relevant function/division and one-third on the achievement of key personal, strategic and behavioural objectives, both short-term and long-term.
Company, divisional and functional performance is measured on the basis of balanced scorecards. Each scorecard is focused on the delivery of key performance metrics including, for example, pre-determined financial targets and, where appropriate, customer service and health and safety targets. With regard to the financial measures, for the 2003/04 financial year, the company scorecard contained stretch targets for earnings before interest and tax, excluding goodwill amortisation and exceptional items, (“EBIT”), earnings per share, excluding goodwill amortisation and exceptional items, (“EPS”), dividend cover, cash flow and return on capital.
ScottishPower Annual Report and Accounts 2003/04 73
Remuneration Report of the Directors
Objectives are set annually by the Committee and performance against these is reviewed by the Committee at the half year and year end. In determining annual incentive payments for 2003/04, the Remuneration Committee gave detailed consideration to out turn against target in relation to company, divisional/functional and personal performance. Payments made to executive directors were within the range of 83% to 90% of the maximum available opportunity, which was 75% of salary for 2003/04, representing exceptional personal contributions by the executive directors to the financial and operational performance of the company.
Executive Share Plans
The company currently operates a performance share plan, known as the Long Term Incentive Plan (“LTIP”), and an Executive Share Option Plan 2001 (“ExSOP”) for executive directors and other senior managers.
Under the LTIP, awards to acquire shares in ScottishPower at nil or nominal cost are made to the participants up to a maximum value equal to 75% of base salary. The award will vest only if the Committee is satisfied that there has been sustained underlying performance of the company and, to this end, certain gateway performance targets are measured and the Committee reviews performance against these measures when determining if awards vest. The measures relate to the key financial performance indicators of the company and customer service standards. These measures provide a mechanism to safeguard stakeholder interests and provide an overview of the financial and operational success of the business.
The number of shares which actually vest is dependent upon the company’s comparative Total Shareholder Return (“TSR”) performance, over a three-year performance period. TSR measures ScottishPower’s comparative performance against key competitors and only provides rewards if ScottishPower is at least equal to the median performance of appropriate comparators. The Committee chose TSR as the performance measure for the LTIP as it believes that it provides a clear link to the creation of shareholder value.
LTIP awards were granted to 46 directors and senior executives during the year (Award 8). TSR performance is measured against an international comparator group of 37 major energy companies, as identified below.
AES Corp; American Electric Power Inc; Calpine Corp; Centrepoint Energy Inc; Centrica; Chubu Electric Power Co Inc; CLP Holdings Limited; Constellation Energy Group Inc; Dominion Resources Inc; Duke Energy Corp; Dynegy Inc; Edison International; El Paso Corp; Electrabel SA; Electricidade de Portugal SA; Endesa SA; Ente Nazionale per l’Energia Elettrica SpA (Enel); Entergy Corp; Exelon; FirstEnergy Corp; FPL Group Inc; Gas Natural SDG SA; Iberdrola SA; Kansai Electric Power Co Inc; National Grid Transco plc; PPL Corp; Progress Energy Inc; Public Service Enterprise Group Inc; RWE AG; Scottish and Southern Energy plc; Southern Company Inc; Tenaga Nasional Bhd; Tokyo Electric Power Co Inc; TXU Corp; Union Fenosa; Williams Companies Inc; and Xcel Energy Inc.
No shares vest unless the company’s TSR performance is at least equal to the median performance of the comparator group, at which point 40% of the initial award vests. 100% of the shares vest if the company’s performance is equal to or exceeds the top quartile. The number of shares that vest for performance between these two points is determined on a straight-line basis.
For LTIP Award 5, which had the potential to vest during the year, TSR performance was measured against that of the FTSE 100 index and an index of the Electricity and Water sectors of the FTSE All Share Index over the three-year period to 4 May 2003. After careful consideration, the Committee determined that the gateway measures relating to the financial and customer service performance of the company had been achieved. As the company was ranked between the median and upper quartile TSR performance levels against the FTSE 100 companies, a proportion of the 50% of the initial award measured against these companies vested. With regard to the 50% of the initial award measured against the Electricity and Water sector companies, the TSR performance of ScottishPower was below the median of the group and this part of the initial award lapsed with no vesting of shares. At the maximum level of participation whereby awards were made over shares with an initial value of 75% of base salary at May 2000, an award equal to 35.4% of base salary became available for exercise by participants at the end of the one-year deferral period in May 2004.
The Committee has approved the operation of the LTIP for 2004/05 and has agreed to place a greater focus on performance and potential in determining LTIP participation. As an extra incentive and retention tool, the Committee agreed to include selected key high potential/high performance individuals in the LTIP as identified by the talent management process (if not already at a level that qualifies for participation). The Committee has also agreed that participants who would normally receive an LTIP award as a result of their level in the company will only do so if they achieve a certain pre-determined level of performance as determined by the company’s performance management system. No other significant changes to the operation of the LTIP have been implemented for 2004/05.
Options were granted at market value to 292 directors and other executives across the company during the year. Executive directors in post at May 2003 received an award of options with a value equivalent to 200% of base salary. Options granted to UK executives under the ExSOP are subject to the performance criterion that the average annual percentage increase in the company’s EPS be at least 3% (adjusted for any increase in the Retail Price Index). The Committee believes that EPS is an appropriate measure for the purposes of testing the ExSOP because it is based on the underlying financial performance of the company. This criterion is assessed at the end of the third financial year, the first year being the financial year starting immediately before the date of grant. If not satisfied on the third anniversary, the criterion may be retested, from the
74 ScottishPower Annual Report and Accounts 2003/04
same base, on the fourth and fifth anniversaries of grant. Unvested options lapse at the fifth anniversary.
The Committee has approved the operation of the ExSOP for 2004/05 and, as outlined with regard to the LTIP above, has agreed to place a greater focus on performance and potential in determining ExSOP participation. No other significant changes to the operation of the ExSOP have been implemented for 2004/05.
Performance Graph
The Directors’ Remuneration Report Regulations require that a graph be presented showing the company’s TSR performance against the TSR performance of a broad equity market index over a five-year period. The FTSE 100 has been chosen because it is the principal index in which the company’s shares are quoted. The graph below presents the comparative TSR performance of the company during the period 1 April 1999 – 31 March 2004. The graph shows that ScottishPower has outperformed the index over this period.
This graph looks at the value (net of withholding tax), at 31 March 2004, of £100 invested in ScottishPower on 31 March 1999 compared with that of £100 invested in the FTSE 100 Index. The other points plotted are the values at intervening financial year ends.
All-Employee Share Plans
To facilitate high levels of share ownership by employees, the company operates three savings-related share ownership plans. These are all-employee Inland Revenue or Internal Revenue Service approved plans and are not subject to performance conditions. Participation is available to executive directors on the same basis as to all other eligible employees.
Sharesave
Employees domiciled in the UK are eligible to participate in the ScottishPower all-employee Sharesave plan. Under this plan, options are granted over ScottishPower shares at a discount of 20% from the prevailing market price at the time of grant to eligible employees who commit to save up to £250 per month over a period of three or five years.
Employee Share Ownership Plan (“ESOP”)
The company operates an ESOP (also known as a Share Incentive Plan) for all UK domiciled employees. The ESOP enables employees to purchase shares in the company from pre-tax income up to the limits specified in the legislation. The value of these shares is at risk as they are not normally released until the legislation allows. The company matches these shares at no cost to the employee on a one-for-one ratio.
Defined Contribution Savings Plan (“401(k)”)
Employees domiciled in the US are eligible to participate in a tax-beneficial savings plan (known as a 401(k) plan) provided for all US employees. The Plan provides for employee contributions up to statutory limits, which are matched by the company at 50% of the employee contribution up to the first 6% of pay (i.e. a 3% match). The company also makes an additional contribution of 2% of eligible pay for all participants. All contributions to the Plan are invested in a range of investment funds, including ScottishPower ADSs, at the discretion of the participant.
Pension
The UK domiciled executive directors, and other UK senior managers of the company, are provided with pension benefits through the company’s main pension scheme, and through an executive top-up pension plan which provides a maximum pension of two-thirds of final salary on retirement at age 63, reduced where service to age 63 is less than 20 years. Pensionable salary is normally base salary in the 12 months prior to leaving the company although there are prescribed mechanisms for calculating pensionable salary by averaging base salary over a period of up to three out of the last 10 years’ service. The employee contributes 5% of salary to the scheme. Life assurance provision of four times pensionable salary and a widow’s pension of half the executive’s pension on death are provided.
UK domiciled individuals who joined the company on or after 1 June 1989 are subject to the Inland Revenue ‘earnings cap’, introduced by the Finance Act 1989. Entitlement to pension benefits above the cap cannot be provided through the company’s approved pension scheme, and therefore arrangements on an unapproved basis have been made to provide total benefits for executives affected by the legislation as though there was no cap. The total liability calculated on an FRS 17 basis in respect of executives and senior employees arising in relation to unapproved benefits accrued for service for the year to 31 March 2004 was £934,100. The Trustee body of the Executive Top Up Plan is chaired by the Company Secretary.
The US domiciled executive director and other US senior managers of the company participate in a qualified defined
ScottishPower Annual Report and Accounts 2003/04 75
Remuneration Report of the Directors
benefit pension plan and a Supplemental Executive Retirement Plan. The defined benefit plan is a non-contributory retirement plan. Benefits vest after five years of service and are determined by each employee’s years of service with the company, final average pay (the highest 60 consecutive months of eligible pay over the last 120 months of employment) and age at retirement. Pay includes base pay plus annual incentive plan payments up to 10% of annual base pay. The amount of pay considered under the plan is further limited by statute. Benefits under the plan, plus benefits payable from the US Social Security system, at age 65 (normal retirement) are targeted to replace 60%-70% of final average pay after a full career (defined as 30 years) with the company.
As a US domiciled executive director, Judi Johansen participates in the PacifiCorp Supplemental Executive Retirement Plan (“SERP”) which provides additional retirement benefits to a select group of management or highly compensated employees as a means to attract and retain highly effective individuals. Participants receive benefits at retirement based on length of service with the company and average pay in the 60 consecutive months of highest pay out of the last 120 months, and pay for this purpose would include salary and annual incentive plan payments. Benefits are based on 50% of final average pay plus up to an additional 15% of final average pay depending upon whether the company meets certain performance goals set for each fiscal year by the company. Retirement benefits are reduced to reflect Social Security benefits as well as certain prior employer retirement benefits and other retirement benefits from the company’s qualified retirement plan. Participants are entitled to receive full benefits upon retirement after age 60 with at least 15 years of service. Participants are also entitled to receive reduced benefits upon early retirement after age 55 or after age 50 with at least 15 years of service and 5 years of participation in the supplemental plan.
The Committee has reported the pension expense in accordance with the requirements of the UK Listing Authority and Directors’ Remuneration Report Regulations. Pension costs detailed in the Accounts are calculated as the cost of providing benefits accrued in the 2003/04 year, in accordance with appropriate accounting standards.
Benefits
Executive directors are eligible for a range of benefits on which they are assessed for tax. These include the provision of a company car or a cash allowance in lieu of a car, fuel, private medical provision and permanent health insurance. The provision and level of benefits is reviewed regularly to ensure that practice is in line with the market.
The US domiciled executive director participates in post-retirement healthcare plans, subject to the eligibility criteria at termination from the company. Currently, those criteria are termination after age 55 with five or more years of service.
Service Contracts
Ian Russell, Charles Berry and David Nish entered into new service contracts with the company dated 3 June 2003. These are rolling contracts terminable by either party on twelve months’ notice. They contain a payment in lieu of notice provision that allows the company to terminate the contract immediately and a liquidated damages provision which provides for a payment to the director if the company terminates the contract unlawfully. The payment in lieu of notice and liquidated damages provisions are calculated by reference to twelve months’ basic salary and contractual benefits (except bonus as set out below). The company has the discretion to pay these amounts in full on termination of employment or, in line with emerging best practice, in instalments. If instalments are paid, an initial payment will be made in respect of six months’ loss only. Further instalments may be paid if the director has not started alternative employment within six months of the termination date. The director will only receive payment in respect of twelve months’ loss should he or she fail to start alternative employment within nine months of termination. If the director starts alternative employment within nine months of termination, the instalments will be reduced by the basic salary received by the director in his alternative employment.
The director’s entitlement under any performance related pay scheme for the period prior to termination will be unaffected as will any entitlement under any executive share scheme. In addition, the company will pay to the director an amount representing a proportion of his or her maximum annual bonus for the notice period based on the company’s performance against its pre-determined financial objectives. This will be paid at the same time as annual bonuses are paid to other employees providing the director has complied with confidentiality obligations and any restrictive covenants and may be reduced if the director obtains alternative employment.
The new contract does not provide for any additional benefits where termination of a director is as a result of a change in control of the company.
If not otherwise terminated, the service contracts terminate automatically at Normal Retirement Age.
On appointment to the Board, Simon Lowth and Judi Johansen entered into new service contracts with the company on the same basis as for existing directors as outlined above. The effective date of these contracts was 1 September 2003 for Simon Lowth and 1 October 2003 for Judi Johansen. The company’s policy is that all new directors will be offered service contracts on the terms outlined above.
The Committee’s policy on early termination is to emphasise the duty to mitigate to the fullest extent practicable. Senior managers within the company have notice periods ranging from six months to one year.
The Chairman, Charles Miller Smith, does not have a service contract with the company.
76 ScottishPower Annual Report and Accounts 2003/04
Future Incentive Strategy
During the year the Remuneration Committee has given detailed consideration to company strategy as it impacts on our remuneration philosophy for executive directors and other key senior executives.
ScottishPower’s strategic focus continues to be on organic growth and continual operational improvement in our existing divisions. It is expected that this will enhance shareholder value and provide dividend growth in line with the growth in earnings. The Remuneration Committee believes strongly that, to support our strategy, the balance of incentives needs to be shifted towards achieving higher returns from improved operational performance.
The Remuneration Committee has developed the revised approach below for 2004/05 in order to refocus our incentive policy:
| • | Make no further awards under the ExSOP after the May 2004 award. |
| • | Increase the bonus plan levels for the year beginning 1 April 2004 but deliver that increase in the form of shares which are deferred for 3 years. |
| • | Retain the LTIP in the existing form until the plan expires at the 2006 AGM, at which time the Remuneration Committee will conduct a further review of our incentive strategy and consult with major shareholders prior to seeking approval for any proposed new plan. |
Under the new arrangements the target annual bonus for executive directors will be increased from 56% to 70% of salary and the maximum annual bonus from 75% to 100% of base salary. The cash payments at the year end would be the same as under the existing plan for achieving the equivalent level of performance. The additional bonus of one-third of the cash bonus would be payable in ScottishPower shares deferred for three years.
The deferred shares will be bought in the employee’s name and the certificate lodged with the company for three years, but dividend and voting rights will be retained by the employee. There would be no award of matching shares at the end of the three-year deferral period. As the deferred shares are a part of an annual bonus award, the shares would be returned to the employee in circumstances involving a termination of employment.
In determining the structure of the annual incentive plan for 2004/05, the Remuneration Committee gave detailed consideration to the metrics used and the payment calibration scale given the increase in focus on this element of the remuneration package. As a result, the Committee decreased the percentage bonus payment for achieving stretch budget.
The 2004/05 annual incentive plan for the Chief Executive is based 50% on the achievement of key company financial targets, including EPS, dividend cover, cash flow and return on capital. A further 40% is based on the achievement of key strategic objectives (including appropriate pre-determined targets in relation to customer service and health and safety, amongst others) and 10% is based on cultural and leadership behaviours, including the results of a 360º leadership survey of feedback from reporting manager, peers and direct reports.
For the other four executive directors, 25% of bonus is based on the achievement of key company financial targets, 25% is based on the achievement of key strategic objectives, 40% on the achievement of the appropriate function/division balanced scorecard targets (with financial metrics and performance targets relating to the function/division, including, where appropriate, customer service and health and safety metrics) and 10% is based on cultural and leadership behaviours, including the results of a 360º leadership survey of feedback from reporting manager, peers and direct reports.
External Non-Executive Appointments
The company encourages its directors to become non-executive directors of other companies, provided that these appointments are not with competing companies, are not likely to lead to any conflicts of interest, and do not require extensive commitments of time which would prejudice their roles within the company. This serves to add to their personal and professional experience and knowledge, to the benefit of the company. Any fees derived from such appointments may be retained by the executives.
Remuneration Policy for Non-Executive Directors
The remuneration of non-executive directors is determined by the Chairman and the executive directors of the Board and, for the period 1 April 2003 to 30 September 2003, consisted of a base fee of £24,000 p.a., a committee membership fee of £3,500 p.a., a fee of £7,500 p.a. for chairing the Audit Committee and the Remuneration Committee, and an international travel fee of £1,000 for attending a tranche of meetings that involve a Transatlantic journey.
Due to the increased responsibility of non-executive roles in recent years, and as fees were not set at a competitive market level (based on analyses provided by Towers Perrin), the fees payable to non-executive directors were reviewed during the year for the first time since December 1999.
As a result of the review, for the period 1 October 2003 to 31 March 2004 remuneration consisted of a base fee of £31,000 p.a., a committee membership fee of £5,000 p.a. (not paid to a committee chairman), a fee of £15,000 p.a. for chairing the Audit Committee and the Remuneration Committee, and an international travel fee of £1,000 for attending a tranche of meetings that involve a Transatlantic journey.
With effect from 1 April 2004, the Board introduced a fee of £10,000 p.a. for chairing the Group Finance Committee of the Board and £3,000 p.a. to be a member. Such fees are only paid to the independent non-executive directors who serve on the Group Finance Committee.
ScottishPower Annual Report and Accounts 2003/04 77
Remuneration Report of the Directors
In line with best practice, the independent non-executive directors do not have service contracts, are not members of the company’s pension schemes and do not participate in any bonus, share option or other profit or long-term incentive plan. Full details of the remuneration of the non-executive directors are contained in Table 44.
Compensation of Directors and Officers
For US reporting purposes, it is necessary to provide information on compensation and interests for directors and officers. The aggregate amount of compensation paid by the group to all directors and officers of the company, as a group, was £5,872,296.
During 2003/04 the cost to the group to provide pension, retirement or similar benefits for directors and officers of the company pursuant to any existing plan provided or contributed to by the group was £1,933,134 (calculated in accordance with Statement of Standard Accounting Practice 24 ‘Accounting for pension costs’).
Interest of Management in Certain Transactions
There have been no material transactions during the group’s three most recent financial years, nor are there presently proposed to be any material transactions to which the company or any of its subsidiaries was or is a party and in which any director or officer, or 10% shareholder, or any relative or spouse thereof or any relative of such a spouse, who had the same home as such person or who is a director or officer of any subsidiary of the company has or is to have a direct or indirect material interest.
During the group’s three most recent financial years there has been no, and at present there is no, outstanding indebtedness to the company or any of its subsidiaries owed or owing by any director or officer of the group or any associate thereof.
Directors’ Interests
Other than as disclosed, none of the directors had a material interest in any contract of significance with the company and its subsidiaries during or at the end of the financial year. The directors’ interests, all beneficial, in the ordinary shares of the company, including interests in options under the company’s ExSOP and Sharesave Scheme and awards under the LTIP, are shown on pages 81 to 83.
Directors’ Emoluments
Table 44 provides a breakdown of the total emoluments of the Chairman and all the directors in office during the year ended 31 March 2004.
Directors’ Pension Benefits
Details of pension benefits earned by the executive directors during the year are shown in Table 45.
78 ScottishPower Annual Report and Accounts 2003/04
The following tables provide details of the remuneration, pensions and share interests of the directors and the information is audited.
Table 44 – Directors’ Emoluments 2003/04
| Basic Salary £ 000’s |
Bonuses £ 000’s |
Benefits in Kind £ 000’s |
Total £ 000’s | ||||||||||||||
| Total Emoluments |
2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
2004 |
2003 | |||||||||
| Chairman and executive directors |
|||||||||||||||||
| Charles Miller Smith (Chairman) |
275.0 | 235.0 | — | — | 4.7 | 14.0 | 279.7 | 249.0 | |||||||||
| Ian Russell |
650.0 | 550.0 | 414.4 | 412.5 | 32.7 | 32.8 | 1,097.1 | 995.3 | |||||||||
| Charles Berry |
315.0 | 300.0 | 212.6 | 225.0 | 27.4 | 25.8 | 555.0 | 550.8 | |||||||||
| Judi Johansen (appointed 1 October 2003) |
206.6 | — | 258.3 | * | — | 3.2 | — | 468.1 | — | ||||||||
| Simon Lowth (appointed 1 September 2003) |
242.1 | — | 151.3 | — | 6.7 | — | 400.1 | — | |||||||||
| David Nish |
415.0 | 350.0 | 269.8 | 262.5 | 31.7 | 31.2 | 716.5 | 643.7 | |||||||||
| Total |
2,103.7 | 1,435.0 | 1,306.4 | 900.0 | 106.4 | 103.8 | 3,516.5 | 2,438.8 | |||||||||
| Fees £ 000’s |
Bonuses £ 000’s |
Benefits in Kind £ 000’s |
Total £ 000’s | ||||||||||||||
| 2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
2004 |
2003 | ||||||||||
| Non-executive directors (fees and expenses) |
|||||||||||||||||
| Euan Baird |
32.8 | 29.5 | — | — | 2.9 | 0.3 | 35.7 | 29.8 | |||||||||
| Mair Barnes |
38.0 | 33.0 | — | — | 3.4 | 0.3 | 41.4 | 33.3 | |||||||||
| Donald Brydon (appointed 30 May 2003) |
29.6 | — | — | — | 0.1 | — | 29.7 | — | |||||||||
| Philip Carroll (resigned 15 May 2003, re-appointed 20 October 2003) |
23.8 | 31.5 | — | — | 1.5 | 5.0 | 25.3 | 36.5 | |||||||||
| Sir Peter Gregson |
51.0 | 44.0 | — | — | 3.0 | 1.2 | 54.0 | 45.2 | |||||||||
| Nolan Karras* * |
53.9 | 52.7 | — | — | 3.7 | 14.8 | 57.6 | 67.5 | |||||||||
| Allan Leighton (resigned 12 June 2002) |
— | 5.5 | — | — | — | 0.0 | — | 5.5 | |||||||||
| Ewen Macpherson (resigned 25 July 2003) |
12.8 | 40.5 | — | — | 0.3 | 0.0 | 13.1 | 40.5 | |||||||||
| Nick Rose (appointed 19 February 2003) |
38.8 | 3.7 | — | — | 1.7 | 0.0 | 40.5 | 3.7 | |||||||||
| Total |
280.7 | 240.4 | — | — | 16.6 | 21.6 | 297.3 | 262.0 | |||||||||
Other emoluments
| * | Judi Johansen’s base salary is disclosed on a pro-rata basis for the six months of the year which she served as a Board director. The bonus figure represents the annual incentive payment for the whole twelve months of the year 2003/04. The conversion rate used is £1 = $1.694, being the average exchange rate during the year. |
| ** | Nolan Karras received emoluments in the US of £9,637 (2003 £16,807) in respect of services to the PacifiCorp and Utah advisory boards in the form of cash and shares. These amounts are included within ‘Fees’ in the above table. |
| (i) | The emoluments of the highest paid director (Ian Russell) excluding pension contributions were £1,097,144 (2003 £995,280). In addition, gains on exercise of share options during the year by Ian Russell amounted to £46,416 (2003 £nil). Details of other share related incentives are contained in Tables 46 and 47. |
| (ii) | Ian Russell has an entitlement under the unapproved pension benefits described further in Table 45. |
ScottishPower Annual Report and Accounts 2003/04 79
Remuneration Report of the Directors
Table 45 – Defined Benefits Pension Plans 2003/04
| Transferred - in benefits |
Additional pension earned in year (net of inflation) |
Accrued pension at end of year |
(A) Transfer |
Value of accrued pension at start of year |
Value of accrued pension at end of year |
(B) Total change |
|||||||||
| £ p.a. | £ p.a. | £ p.a. | £ | £ | £ | £ | |||||||||
| Ian Russell |
17,838 | 43,715 | 208,489 | 560,208 | 1,915,459 | 2,637,029 | 716,620 | ||||||||
| Charles Berry |
0 | 11,109 | 111,004 | 141,099 | 1,197,029 | 1,416,165 | 214,185 | ||||||||
| Judi Johansen* |
0 | 18,400 | 42,658 | 66,888 | 74,929 | 160,104 | 85,176 | ||||||||
| Simon Lowth** |
33,371 | 5,782 | 40,120 | 50,803 | 347,325 | 347,141 | (3,071 | ) | |||||||
| David Nish |
44,267 | 21,682 | 103,852 | 211,386 | 804,254 | 1,020,190 | 210,986 | ||||||||
| * | Judi Johansen was appointed to the Board on 1 October 2003. The figures shown above relate to the period between 1 April 2003 and 31 March 2004, and the value “at start of year” relates to the value at 1 April 2003. Part of her benefits are provided in defined contribution form, through a company 401(k) plan. The figures in the table do not include any 401(k) element. The company contribution payable to the 401(k) plan in respect of Judi Johansen for the period 1 April 2003 to 31 March 2004 was £7,132. The conversion rate used is £1 = $1.694, being the average exchange rate during the year. See also note (xi) regarding her potential entitlement to post-retirement healthcare benefits. |
| ** | Simon Lowth joined the company as a director on 1 September 2003. The figures shown above relate to the period between 1 September 2003 and 31 March 2004. |
(i) The accrued entitlement of the highest paid director (Ian Russell) was £208,489 (2003 £160,286). During the year, retirement benefits were accrued under the defined benefits pension schemes in respect of 5 directors (2003 3 directors).
(ii) The transfer value of the increases after inflation (A) represents the current capital sum which would be required, using demographic and financial assumptions, to produce an equivalent increase in accrued pension and ancillary benefits, excluding the statutory inflationary increase, and after deduction of members’ contributions. Although the transfer value represents a liability, to the Pension Scheme in respect of approved benefits and to the company in respect of any unapproved benefits, it is not a single sum paid or due to be paid to the individual director and cannot therefore meaningfully be added to the annual remuneration. Instead, this value would not be payable until the director’s retirement date, and thereafter would be spread over the remainder of his lifetime (and also covering the cost of dependants’ benefits after his death).
(iii) The total change in value (B) in the last column of the table above reflects the following elements:
| 1. | changes to the economic and demographic assumptions underlying the transfer value basis over the year |
| 2. | any increases in pensionable salary received during the year |
| 3. | the completion of another year of pensionable service during the year |
| 4. | the directors are a year closer to drawing their pensions, which increases their pension value (all other things being equal). |
The change in the amount of the transfer values over the year includes the effect of fluctuations in factors that are beyond the control of the company and its directors, such as stockmarket movements and long-term interest rates. Due to market conditions at the end of the year, the transfer value basis at that time provides lower transfer values than the basis at the start of the year (all other things being equal). This has led to a negative figure in the final column (B) of the above table for Simon Lowth i.e. a fall in value of his total pension.
(iv) The accrued pension shown is that which would be paid annually on retirement based upon service to the end of the year. Members of the company’s schemes have the option of paying additional voluntary contributions; neither the contributions nor the resulting benefits are included in the above table.
(v) Directors who joined the pension scheme on or after 1 June 1989 are subject to the earnings cap, introduced in the Finance Act 1989. Pension entitlements which cannot be provided through the company’s approved schemes due to the earnings cap are provided through unapproved pension arrangements, details of which are included in the Remuneration Report. The pension benefits disclosed above include approved and unapproved pension arrangements.
(vi) The increase in accrued pension during the year excludes the increase due to RPI inflation as measured at December 2003 (2.8%).
(vii) The value of directors’ entitlements has been calculated on the basis of actuarial advice in accordance with Actuarial Guidance note GN11, in two parts: the approved element being based upon the normal cash equivalent transfer value assumptions; the unapproved element being calculated in line with FRS 17 assumptions. For the transfer value of increases after inflation, the figures shown represent values after deducting directors’ contributions.
(viii) Transferred-in benefits represent pension rights accrued in respect of previous employments. The accrued pension shown at the end of the year includes transferred-in benefits.
(ix) The total liabilities, calculated on an FRS 17 basis, arising in relation to UK unapproved benefits for all executives and senior employees for service for the year to 31 March 2004 was £934,100 (2003 £208,700). This figure relates only to the cost of benefits accruing over the year but does not include any finance items. It therefore differs from the full FRS17 charge for unapproved benefits over the same period.
(x) All benefits above are provided on a defined benefit basis.
(xi) Judi Johansen may also be eligible to participate in the company’s post-retirement healthcare plans, providing that she meets the eligibility criteria at the time she terminates or retires from the company. Currently those criteria are termination after age 55 with five of more years of service.
80 ScottishPower Annual Report and Accounts 2003/04
Table 46 – Directors’ Interests in ScottishPower Shares
| Ordinary shares |
Share options (Executive1) |
Share options (Sharesave) |
Long Term Incentive Plan | |||||||||||||||||
| 31.3.04 |
1.4.03 (or date of appointment if later) |
31.3.04 |
1.4.03 (or date of appointment if later) |
31.3.04 |
1.4.03 (or date of appointment if later) |
31.3.04 |
1.4.03 (or date of appointment if later) | |||||||||||||
| **Vested |
*Potential |
**Vested |
*Potential | |||||||||||||||||
| Charles Miller Smith |
11,000 | 11,000 | — | — | — | — | — | — | — | — | ||||||||||
| Euan Baird |
114,363 | 110,770 | — | — | — | — | — | — | — | — | ||||||||||
| Mair Barnes |
1,400 | 1,400 | — | — | — | — | — | — | — | — | ||||||||||
| Donald Brydon (appointed 30 May 2003) |
3,000 | — | — | — | — | — | — | — | — | — | ||||||||||
| Philip Carroll |
||||||||||||||||||||
| (resigned 15 May 2003, re-appointed 20 October 2003) |
4,000 | 4,000 | — | — | — | — | — | — | — | — | ||||||||||
| Sir Peter Gregson |
1,257 | 1,186 | — | — | — | — | — | — | — | — | ||||||||||
| Nolan Karras |
39,297 | 36,346 | — | — | — | — | — | — | — | — | ||||||||||
| Nick Rose |
5,128 | — | — | — | — | — | — | — | — | — | ||||||||||
| Ian Russell |
•127,376 | 87,741 | 844,192 | 498,678 | 5,290 | 4,371 | 21,217 | 323,243 | 12,682 | 238,675 | ||||||||||
| Charles Berry |
•23,506 | 22,553 | 422,884 | 255,443 | 2,941 | 2,941 | 11,968 | 161,734 | — | 124,328 | ||||||||||
| Judi Johansen (appointed 1 October 2003) |
88,960 | 82,671 | 898,000 | 952,500 | — | — | — | 86,627 | — | 86,627 | ||||||||||
| Simon Lowth (appointed 1 September 2003) |
— | — | — | — | — | — | — | — | — | — | ||||||||||
| David Nish |
•13,964 | 12,742 | 517,234 | 296,636 | 2,509 | 2,509 | 10,880 | 197,602 | — | 137,954 | ||||||||||
None of the directors has an interest in ordinary shares which is greater than 1% of the issued share capital of the company.
| 1 | Includes options granted under the Executive Share Option Plan 2001 and, where applicable, the PacifiCorp Stock Incentive Plan. |
| * | These shares represent, in each case, the maximum number of shares which the directors may receive, dependent on the satisfaction of performance criteria as approved by shareholders in connection with the Long Term Incentive Plan. |
| ** | These shares represent the number of shares the directors are entitled to receive when the LTIP award becomes exercisable calculated according to the performance criteria measured over the three-year performance period. |
| • | These shares include the number of shares which the directors hold in the Employee Share Ownership Plan, shown below. |
| Free shares |
Partnership shares |
Matching shares |
Dividend shares |
Total | ||||||||||||||||
| 31.3.04 |
1.4.03 |
31.3.04 |
1.4.03 |
31.3.04 |
1.4.03 |
31.3.04 |
1.4.03 |
31.3.04 |
1.4.03 | |||||||||||
| Ian Russell |
50 | 50 | 1,210 | 799 | 1,210 | 799 | 266 | 135 | 2,736 | 1,783 | ||||||||||
| Charles Berry |
50 | 50 | 1,210 | 799 | 1,210 | 799 | 266 | 135 | 2,736 | 1,783 | ||||||||||
| David Nish |
50 | 50 | 1,210 | 799 | 1,210 | 799 | 266 | 135 | 2,736 | 1,783 | ||||||||||
Between 31 March 2004 and 20 May 2004, Ian Russell, Charles Berry and David Nish each acquired 65 Partnership shares and 65 Matching shares as part of the regular monthly transactions of the Employee Share Ownership Plan; and Judi Johansen and Nolan Karras acquired 447.609 and 36.1664 ScottishPower ADSs (1,790 and 144 ordinary shares) respectively as part of the PacifiCorp Compensation Reduction Plan. Additionally, 1,225 ADSs (4,900 ordinary shares) held by Judi Johansen in the form of Unvested Restricted Stock in the PacifiCorp Stock Incentive Plan, vested and became non-forfeitable on 24 April 2004 and, in accordance with the deferral election executed by Judi Johansen, were all immediately transferred into the PacifiCorp Compensation Reduction Plan. Otherwise, there have been no changes to the directors’ interests between 31 March 2004 and 20 May 2004.
Table 47 – Directors’ Interests in Performance and Other Share Plans at 31 March 2004
| 1 April 2003 (or date of appointment if later) |
Granted |
Exercised |
Lapsed# |
31 March 2004 |
Option exercise price |
Date exercised |
Market price at date of exercise |
Date from which exercisable |
Expiry date | |||||||||||
| (pence) | (pence) | |||||||||||||||||||
| Long Term Incentive Plan |
||||||||||||||||||||
| Ian Russell |
12,682 | — | 12,682 | — | — | nil | 8 Sep 03 | 366.0 | 07 May 02 | 06 May 05 | ||||||||||
| 45,000 | — | — | 23,783 | 21,217 | nil | 05 May 04 | 04 May 07 | |||||||||||||
| 92,075 | — | — | — | 92,075 | nil | 04 May 04 | 03 May 08 | |||||||||||||
| 101,600 | — | — | — | 101,600 | nil | 02 May 05 | 01 May 09 | |||||||||||||
| — | 129,568 | — | — | 129,568 | nil | 10 May 06 | 09 May 10 | |||||||||||||
| 251,357 | 129,568 | 12,682 | 23,783 | 344,460 | ||||||||||||||||
| Charles Berry |
25,384 | — | — | 13,416 | 11,968 | nil | 05 May 04 | 04 May 07 | ||||||||||||
| 43,526 | — | — | — | 43,526 | nil | 04 May 04 | 03 May 08 | |||||||||||||
| 55,418 | — | — | — | 55,418 | nil | 02 May 05 | 01 May 09 | |||||||||||||
| — | 62,790 | — | — | 62,790 | nil | 10 May 06 | 09 May 10 | |||||||||||||
| 124,328 | 62,790 | — | 13,416 | 173,702 | ||||||||||||||||
| Judi Johansen |
36,794 | — | — | — | 36,794 | nil | 02 May 05 | 01 May 09 | ||||||||||||
| (appointed 1 October 2003) |
49,833 | — | — | — | 49,833 | nil | 10 May 06 | 09 May 10 | ||||||||||||
| 86,627 | — | — | — | 86,627 | ||||||||||||||||
| David Nish |
23,076 | — | — | 12,196 | 10,880 | nil | 05 May 04 | 04 May 07 | ||||||||||||
| 50,223 | — | — | — | 50,223 | nil | 04 May 04 | 03 May 08 | |||||||||||||
| 64,655 | — | — | — | 64,655 | nil | 02 May 05 | 01 May 09 | |||||||||||||
| — | 82,724 | — | — | 82,724 | nil | 10 May 06 | 09 May 10 | |||||||||||||
| 137,954 | 82,724 | — | 12,196 | 208,482 | ||||||||||||||||
| # | During the year, the performance period for the awards granted under the Long Term Incentive Plan on 5 May 2000 ended and, on the basis of the company’s total shareholder return, 47% of shares under awards vested. However, these awards may not be exercised until the fourth anniversary of grant and are exercisable until the seventh anniversary. The market price of ScottishPower ordinary shares at the date of grant of these awards was 548 pence and on 2 May 2003, being the last trading date before vesting, was 388.25 pence. |
Long Term Incentive Plan awards granted before 2001 became exercisable on the fourth anniversary of grant. Awards granted in 2001 and subsequently become exercisable on the third anniversary of grant, as approved by shareholders.
Awards granted during the year were granted for no consideration. The market value of a ScottishPower share at the date of grant was 376.25 pence.
ScottishPower Annual Report and Accounts 2003/04 81
Remuneration Report of the Directors
Table 47 – Directors’ Interests in Performance and Other Share Plans at 31 March 2004 continued
| 1 April 2003 (or date of appointment if later) |
Granted |
Exercised |
Lapsed |
31 March 2004 |
Option exercise price |
Date exercised |
Market price at date of exercise |
Date from which exercisable |
Expiry date | |||||||||||||
| (pence) | (pence) | |||||||||||||||||||||
| Executive Share Option Plan 2001 |
||||||||||||||||||||||
| Ian Russell |
227,743 | — | — | — | 227,743 | 483.0 | 21 Aug 04 | 21 Aug 11 | ||||||||||||||
| 270,935 | — | — | — | 270,935 | 406.0 | 02 May 05 | 02 May 12 | |||||||||||||||
| — | 345,514 | — | — | 345,514 | 376.3 | 10 May 06 | 10 May 13 | |||||||||||||||
| 498,678 | 345,514 | — | — | 844,192 | ||||||||||||||||||
| Charles Berry |
107,660 | — | — | — | 107,660 | 483.0 | 21 Aug 04 | 21 Aug 11 | ||||||||||||||
| 147,783 | — | — | — | 147,783 | 406.0 | 02 May 05 | 02 May 12 | |||||||||||||||
| — | 167,441 | — | — | 167,441 | 376.3 | 10 May 06 | 10 May 13 | |||||||||||||||
| 255,443 | 167,441 | — | — | 422,884 | ||||||||||||||||||
| Judi Johansen |
61,824 | — | — | — | 61,824 | 320.3 | 02 May 05 | 02 May 12 | ||||||||||||||
| (appointed 1 October 2003) |
61,824 | — | — | — | 61,824 | 320.3 | 02 May 03 | 02 May 12 | ||||||||||||||
| 61,824 | — | — | — | 61,824 | 320.3 | 02 May 04 | 02 May 12 | |||||||||||||||
| 61,828 | — | — | — | 61,828 | 320.3 | 02 May 05 | 02 May 12 | |||||||||||||||
| 81,968 | — | — | — | 81,968 | 331.9 | 10 May 04 | 10 May 13 | |||||||||||||||
| 81,964 | — | — | — | 81,964 | 331.9 | 10 May 05 | 10 May 13 | |||||||||||||||
| 81,968 | — | — | — | 81,968 | 331.9 | 10 May 06 | 10 May 13 | |||||||||||||||
| 493,200 | — | — | — | 493,200 | ||||||||||||||||||
| David Nish |
124,223 | — | — | — | 124,223 | 483.0 | 21 Aug 04 | 21 Aug 11 | ||||||||||||||
| 172,413 | — | — | — | 172,413 | 406.0 | 02 May 05 | 02 May 12 | |||||||||||||||
| — | 220,598 | — | — | 220,598 | 376.3 | 10 May 06 | 10 May 13 | |||||||||||||||
| 296,636 | 220,598 | — | — | 517,234 | ||||||||||||||||||
| PacifiCorp Stock Incentive Plan |
||||||||||||||||||||||
| Judi Johansen |
76,464 | — | — | — | 76,464 | 340.9 | 25 Jan 02 | 25 Jan 11 | ||||||||||||||
| (appointed 1 October 2003) |
76,468 | — | — | — | 76,468 | 340.9 | 25 Jan 03 | 25 Jan 11 | ||||||||||||||
| 76,468 | — | — | — | 76,468 | 340.9 | 25 Jan 04 | 25 Jan 11 | |||||||||||||||
| 76,464 | — | 54,000 | — | 22,464 | 349.6 | 8 Mar 04 | 369.5 | ** | 24 Apr 02 | 24 Apr 11 | ||||||||||||
| 76,468 | — | — | — | 76,468 | 349.6 | 24 Apr 03 | 24 Apr 11 | |||||||||||||||
| 76,468 | — | — | — | 76,468 | 349.6 | 24 Apr 04 | 24 Apr 11 | |||||||||||||||
| 458,800 | — | 54,000 | — | 404,800 | ||||||||||||||||||
| Sharesave Scheme |
||||||||||||||||||||||
| Ian Russell |
4,371 | — | — | 4,371 | — | 386.0 | 01 Sep 06 | 28 Feb 07 | ||||||||||||||
| — | 5,290 | — | — | 5,290 | 301.0 | 01 Sep 08 | 28 Feb 09 | |||||||||||||||
| 4,371 | 5,290 | — | 4,371 | 5,290 | ||||||||||||||||||
| Charles Berry |
2,941 | — | — | — | 2,941 | 323.0 | * | 01 Sep 05 | 28 Feb 06 | |||||||||||||
| 2,941 | — | — | — | 2,941 | ||||||||||||||||||
| David Nish |
2,509 | — | — | — | 2,509 | 386.0 | * | 01 Sep 04 | 28 Feb 05 | |||||||||||||
| 2,509 | — | — | — | 2,509 | ||||||||||||||||||
| * | Denotes options granted under a three-year scheme. |
| ** | The exercise of PacifiCorp Stock Incentive Plan options by Judi Johansen on 8 March 2004 was over 13,500 ADSs at US$25.70 per ADS, on which date the market value of a ScottishPower ADS was US$27.46. |
| (i) | The market price of the shares at 31 March 2004 was 380.75 pence and the range during 2003/04 was 344.75 pence to 395.25 pence. |
| (ii) | The Long Term Incentive Plan makes annual awards to acquire shares in ScottishPower at nil or nominal cost to the plan participants up to a maximum value equal to 75% of base salary. The award will vest only if the Remuneration Committee is satisfied that certain performance measures related to the sustained underlying financial performance of the company and sustained underlying performance in certain Customer Service Standards are achieved over a period of three financial years commencing with the financial year preceding the date an award is made. Assuming that such targets have been achieved, the number of shares that can be acquired will be dependent upon how the company ranks in terms of its total shareholder return performance over a three-year period, in comparison to the constituent companies of the FTSE 100 index and the Electricity and Water sectors for awards granted before May 2001. A percentage of each half of the award will vest depending upon the company’s ranking within each of the comparator groups. For awards granted in May 2001 and subsequently, the company’s total shareholder return performance is compared over a three-year period against an international comparator group of major energy companies. A percentage of the award will vest depending upon the company’s ranking within the comparator group. The plan participant may acquire the shares in respect of the percentage of the award which has vested at any time after the third or fourth year, as appropriate, up to the seventh year after the grant of the award. No dividends accrue to participants prior to vesting. |
82 ScottishPower Annual Report and Accounts 2003/04
| (iii) | The company grants options annually under the Executive Share Option Plan 2001 to relevant executives and senior managers at nil or nominal cost. The exercise of options granted to UK executives and senior managers is subject to the performance criterion that the percentage increase in the company’s annualised earnings per share be at least 3% (adjusted for any increase in the Retail Price Index). This criterion is assessed at the end of the third financial year, the first year being the financial year starting immediately before the date of grant. If the criterion is not satisfied over this period, it is tested again at the end of the fourth financial year. If the criterion is not satisfied over this period, it is tested again at the end of the fifth financial year. If the criterion is not satisfied over this period, then the options lapse. The exercise of options granted to US participants is not normally subject to the satisfaction of performance criteria, and they normally become exercisable as follows: one-third of the options from the first anniversary of the date of grant, a further one-third from the second anniversary and the final one-third from the third anniversary of the date of grant. In 2002, an additional, conditional share option award was made to some senior managers, including Judi Johansen, under the Executive Share Option Plan 2001. The exercise of these additional, conditional options is subject to the same exercise period and performance criterion as options granted to UK participants. |
| (iv) | Options granted to Judi Johansen under the PacifiCorp Stock Incentive Plan and the Executive Share Option Plan 2001 are granted over ScottishPower ADSs. For the purposes of the above table, these options, in the case of Judi Johansen, have been converted to ordinary shares as follows: one ScottishPower ADS equals four ScottishPower ordinary shares. The US$ ADS option prices were converted so that they may be represented in terms of ScottishPower ordinary shares. The prices were further converted at the closing exchange rate on 31 March 2004 of £1 = $1.838 so as to be quoted in pence in the table above. |
61,824 options granted to Judi Johansen on 2 May 2002 under the Executive Share Option Plan 2001 became exercisable on 2 May 2003. The market price of ScottishPower ordinary shares on 2 May 2002 was 411.5 pence and on 2 May 2003 was 388.25 pence. 76,468 options granted on 24 January 2001 and a further 76,468 options granted on 24 April 2001 to Judi Johansen under the PacifiCorp Stock Incentive Plan became exercisable on 25 January 2004 and 24 April 2003 respectively. The market price of ScottishPower ordinary shares on 25 January 2001, 24 April 2001, 24 April 2003 and 23 January 2004 (being the last trading date before 25 January 2004) was 438.0 pence, 477.0 pence, 387.5 pence and 358.75 pence respectively.
The option price for Sharesave options is calculated by reference to the middle-market quotation on the day immediately preceding the date of invitation and discounted by 20% in accordance with the Inland Revenue rules for such schemes.
The number of options granted to a director under the Sharesave Scheme is calculated by reference to the total amount which the director agrees to save for a period of three or five years under an Inland Revenue approved savings contract, subject to a current maximum.
Total gains made on exercise of directors’ share options and awards during the year were £60,442 (2003 £33,580). The conversion rate for gains made by Judi Johansen is £1 = $1.694, being the average exchange rate during the year.
| Approved by the Board and signed on its behalf by |
| /s/ Sir Peter Gregson |
| Sir Peter Gregson, Chairman of the Remuneration Committee 25 May 2004 |
ScottishPower Annual Report and Accounts 2003/04 83
Directors’ Responsibility for the Accounts
The directors are required by law to prepare Accounts for each financial year and to present them annually to the company’s members at the Annual General Meeting. The Accounts, of which the form and content are prescribed by the Companies Act 1985 and applicable accounting standards, must give a true and fair view of the state of affairs of the company and of the group as at the end of the financial year, and of the group’s profit or loss for the period.
The directors confirm that suitable Accounting Policies have been used and applied consistently, and that reasonable and prudent judgements and estimates have been made in the preparation of the Accounts for the year ended 31 March 2004. The directors also confirm that applicable accounting standards have been followed and that the Accounts have been prepared on the going concern basis.
The directors are responsible for maintaining proper accounting records and sufficient internal controls to safeguard the assets of the company and of the group and to prevent and detect fraud or any other irregularities.
Auditors
PricewaterhouseCoopers LLP, the company’s auditors, have expressed their willingness to continue in office and a resolution for their re-appointment will be proposed at the Annual General Meeting.
Report of the Directors
The Report of the Directors, comprising the statements and reports on pages 2 to 84 of this Annual Report and Accounts, has been approved by the Board and signed on its behalf by
| /s/ Andrew Mitchell |
| Andrew Mitchell, Secretary 25 May 2004 |
Cautionary Statement for Purposes of the “Safe Harbor”
Provisions of the Private Securities Litigation Reform Act of 1995
Some statements made in this Annual Report and Accounts are 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”, “intend”, “estimate”, “continue”, “plan”, “project”, “target”, “on track to”, “strategy”, “aim”, “seek”, “will meet” or other similar words are also forward looking. These statements are based on our management’s assumptions and beliefs in light of the information available to us. These assumptions involve risks and uncertainties which may cause the actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements.
ScottishPower wishes to caution readers, and others to whom forward-looking statements are addressed, that any such forward-looking statements are not guarantees of future performance and that actual results may differ materially from estimates in the forward-looking statements. ScottishPower undertakes no obligation to revise these forward-looking statements to reflect events or circumstances after the date hereof. Important factors that 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;
– 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;
– the availability of operational capacity of plants;
– weather and weather related impacts;
– the success of reorganizational and cost-saving efforts; and
– development and use of technology, the actions of competitors, natural disasters and other changes to business conditions.
84 ScottishPower Annual Report and Accounts 2003/04
Accounts 2003/04
Accounts 2003/04
| 85 | ||
| 90 | ||
| 92 | ||
| 92 | ||
| 92 | ||
| 93 | ||
| 93 | ||
| 94 | ||
| 95 | ||
| 144 | ||
| 145 | ||
| 146 | ||
| 147 | ||
| 148 | ||
| 149 |
Accounting Policies and Definitions
Definitions
Business segment definitions
ScottishPower defines business segments for management reporting purposes based on a combination of factors, principally differences in products and services and the regulatory environment in which the businesses operate.
Business segments have been included under either ‘continuing operations’ or ‘discontinued operations’ as appropriate.
The business segments of the group are defined as follows:
Continuing operations
United Kingdom
UK Division – Integrated Generation and Supply The generation of electricity from the group’s own power stations, the purchase of external supplies of coal and gas for the generation of electricity, the purchase of external supplies of electricity and gas for sale to customers, together with related billing and collection activities, gas storage, sale of gas to industrial and domestic customers and the sale of electricity to electricity suppliers, in Scotland and England & Wales and full participation in the New Electricity Trading Arrangements (“NETA”) in England & Wales.
Infrastructure Division – Power Systems The transmission and distribution businesses within the group’s authorised area of Scotland and the distribution business of Manweb operating in Merseyside and North Wales and the transportation of units of electricity through the interconnectors connected to the transmission systems of Northern Ireland, England & Wales and the remainder of Scotland.
United States
PacifiCorp A vertically-integrated electric utility that includes the generation, transmission and distribution and sale of electricity to retail, industrial and commercial customers in portions of six western states; Utah, Oregon, Wyoming, Washington, Idaho and California. The operations also include wholesale sales and power purchase transactions with various entities. The state regulatory commissions and Federal Energy Regulatory Commission (“FERC”) regulate the retail and wholesale operations. The subsidiaries of PacifiCorp support its electric utility operations by providing coal mining facilities and services and environmental remediation.
PPM The competitive energy development, origination and marketing business serving wholesale customers in North American markets. Electricity products and services are provided from gas generation and renewable wind generation resources located in the western and mid-western US. Natural gas storage and hub services are provided from gas storage facilities located in Alberta, Canada and in Texas.
Discontinued operations
United Kingdom
Southern Water The provision of water and wastewater services in the south east of England, together with related billing and collection activities. The disposal of the Southern Water business was completed on 23 April 2002.
ScottishPower Annual Report and Accounts 2003/04 85
Accounts 2003/04
Thus The provision of telecommunications services, internet access and information services to national corporates, small and medium-sized enterprises and residential customers. Thus Group plc (“Thus”) was demerged from ScottishPower on 19 March 2002.
Appliance Retailing The retailing and servicing of domestic electrical goods and home entertainment appliances. The business was disposed of and withdrawn from during the year ended 31 March 2002.
Revenue cost definitions
Cost of sales The cost of sales for the group, excluding Southern Water, reflect the direct costs of the generation and purchase of electricity, the purchase and transportation of natural gas, appliance retailing and telecommunications services. For Southern Water, cost of sales represented the cost of extracting water from underground and raw water surface reservoirs and of its treatment and supply to customers and the collection of wastewater and its treatment and disposal.
Transmission and distribution costs The cost of transmitting units of electricity from the power stations through the transmission and distribution networks to customers. It includes the costs of metering, billing and debt collection. This heading is considered more appropriate to the electricity industry than the standard Companies Act heading of distribution costs.
Administrative expenses The indirect costs of businesses, the costs of corporate services, property rates and goodwill amortisation.
Other definitions
Company or ScottishPower Scottish Power plc.
Group Scottish Power plc and its consolidated subsidiaries.
Associated undertakings Entities in which the group holds a long-term participating interest and exercises significant influence.
Joint ventures Entities in which the group holds a long-term interest and shares control with another company external to the group.
Subsidiary undertakings Entities in which the group holds a long-term controlling interest.
Accounting Policies
Basis of accounting
The Accounts have been prepared under the historical cost convention, modified to include the revaluation of certain tangible fixed assets, and in accordance with applicable accounting standards in the UK and, except for the accounting policy for ‘Commodity contracts’, described below, comply with the requirements of the Companies Act 1985. Further details explaining this departure are contained in Note 20(i) to the Accounts.
Basis of consolidation
The group Accounts include the Accounts of the company and its subsidiary undertakings together with the group’s share of results and net assets of associated undertakings and joint ventures.
For commercial reasons certain subsidiaries have a different year end. The consolidation includes the Accounts of these subsidiaries as adjusted for material transactions in the period between the year ends and 31 March.
Use of estimates
The preparation of Accounts in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Accounts and the reported amounts of revenues and expenses during the reporting period. Actual results can differ from those estimates.
Turnover
Turnover comprises the sales value of energy, goods and other services supplied to customers during the year and excludes Value Added Tax and intra-group sales. Turnover from the sale of energy is the value of units supplied during the year and includes an estimate of the value of units supplied to customers between the date of their last meter reading and the year end, based on external data supplied by the electricity and gas market settlement processes. Prior to the disposal of Southern Water in April 2002, turnover also included the sales value of water and wastewater services.
Interest
Interest on the funding attributable to major capital projects is capitalised gross of tax relief during the period of construction and written off as part of the total cost over the operational life of the asset. All other interest payable and receivable is reflected in the profit and loss account as it arises.
Financial instruments
Debt instruments All borrowings are stated at the fair value of consideration received after deduction of issue costs. The issue costs and interest payable on bonds are charged to the profit and loss account at a constant rate over the life of the bond. Premiums and discounts arising on the early repayment of
86 ScottishPower Annual Report and Accounts 2003/04
borrowings are recognised in the profit and loss account as incurred and received.
Interest rate swaps/Forward rate agreements These are used to manage debt interest rate exposures. Amounts payable or receivable in respect of these agreements are recognised as adjustments to interest expense over the period of the contracts. The cash flows from, and gains and losses arising on terminations of, these contracts are recognised as returns on investments and servicing of finance. Where associated debt is not retired in conjunction with the termination of an interest swap, gains and losses are deferred and are amortised to interest expense over the remaining life of the associated debt to the extent that such debt remains outstanding.
Interest rate caps/Swaptions/Options Premiums received and payable on these contracts are amortised over the period of the contracts and are disclosed as interest income and expense. The accounting for interest rate caps and swaptions is otherwise in accordance with interest rate swaps detailed above.
Cross currency interest rate swaps These are used both to hedge foreign exchange and interest rate exposures arising on foreign currency debt and to hedge overseas net investment. Where used to hedge debt issues, the debt is recorded at the hedge contracted rate and accounting is otherwise in accordance with interest rate swaps detailed above. Where used to hedge overseas net investment, spot gains or losses are recorded on the balance sheet and in the statement of total recognised gains and losses, with interest recorded in the profit and loss account. The cash flows from, and gains and losses arising on the termination, repricing or maturity of, cross currency interest rate swaps hedging overseas net investments are recognised as returns on investments and servicing of finance to the extent they relate to interest and as financing to the extent they represent spot gains or losses.
Forward contracts The group enters into forward contracts for the purchase and/or sale of foreign currencies in order to manage its exposure to fluctuations in currency rates and to hedge overseas net investment. The cash flows from forward purchase contracts are classified in a manner consistent with the underlying nature of the hedged transaction. Hence, unrealised gains and losses on contracts hedging forecast transactions are not accounted for until the maturity of the contract. Foreign currency debtors and creditors that are hedged with forward contracts are translated at the contracted rate at the balance sheet date. Spot gains or losses on hedges of the overseas net investments are recorded on the balance sheet and in the statement of total recognised gains and losses with the interest rate differential reflected in the profit and loss account.
Hydroelectric and temperature hedges These instruments are used to hedge fluctuations in weather and temperature in the US. On a periodic basis, the group estimates and records a gain or loss in the profit and loss account corresponding to the total expected future cash flows from these contracts.
Commodity contracts Where there is no physical delivery associated with commodity contracts, they are recorded at fair value on the balance sheet and movements reflected through the profit and loss account. Gas future contracts are undertaken for hedging and proprietary trading purposes. Where the instrument is a hedge, the fair values are initially reflected on the balance sheet and subsequently reflected through the profit and loss account to match the recognition of the hedged item. Where the instrument is for proprietary trading the fair values are reflected through the profit and loss account. Recognition of unrealised gains on commodity contracts in the profit and loss account is not in accordance with the provisions of the Companies Act 1985. The directors consider that compliance with these requirements would lead to the accounts failing to give a true and fair view of the results of the group. Further details of the effect of this accounting policy are provided in Note 20(i) to the Accounts.
Taxation
In accordance with Financial Reporting Standard 19 ‘Deferred tax’, full provision is made for deferred tax on a non-discounted basis.
Goodwill
Purchased goodwill represents the excess of the fair value of the purchase consideration over the fair value of the net assets acquired. Goodwill arising from acquisitions prior to 31 March 1998 was written off against reserves. On disposal of trading entities, the goodwill previously included in reserves is charged to the profit and loss account matched by an equal credit to reserves. Goodwill arising on acquisitions since 1 April 1998 has been capitalised and amortised through the profit and loss account over its estimated useful economic life. Goodwill arising on overseas acquisitions is regarded as a currency asset and is retranslated at the end of each period at the closing rate of exchange.
Tangible fixed assets
Tangible fixed assets are stated at cost or valuation and are generally depreciated on the straight line method over their estimated operational lives. Tangible fixed assets include capitalised employee, interest and other costs which are directly attributable to construction of fixed assets.
Land is not depreciated except in the case of mines (see below). The main depreciation periods used by the group are as set out below.
| Years | ||
| Coal, oil-fired, gas and other generating stations |
22 – 45 | |
| Hydro plant and machinery |
20 – 100 | |
| Other buildings |
40 | |
| Transmission and distribution plant |
20 – 75 | |
| Towers, lines and underground cables |
40 – 60 | |
| Vehicles, computer software costs, miscellaneous equipment and fittings |
3 – 40 | |
ScottishPower Annual Report and Accounts 2003/04 87
Accounts 2003/04
The carrying values of tangible fixed assets are reviewed for impairment in periods if events or changes in circumstances indicate the carrying value may not be recoverable. For those assets with estimated remaining useful economic lives of more than 50 years, impairment reviews are undertaken annually. Impairment losses are recognised in the period in which they are identified.
Mine reclamation and closure costs Provision is made for mine reclamation and closure costs when an obligation arises out of events prior to the year end. The amount recognised is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. A corresponding tangible fixed asset is also created of an amount equal to the provision. This asset, together with the cost of the mine, is subsequently depreciated on a unit of production basis. The unwinding of the discount is included within net interest and similar charges.
Decommissioning costs Provision is made for the estimated decommissioning costs at the end of the producing lives of the group’s power stations on a discounted basis. Capitalised decommissioning costs are depreciated over the useful lives of the related assets. The unwinding of the discount is included within net interest and similar charges.
Leased assets
As lessee Assets leased under finance leases are capitalised and depreciated over the shorter of the lease periods and the estimated operational lives of the assets. The interest element of the finance lease repayments is charged to the profit and loss account in proportion to the balance of the capital repayments outstanding. Rentals payable under operating leases are charged to the profit and loss account on a straight line basis.
As lessor Rentals receivable under finance leases are allocated to accounting periods to give a constant periodic rate of return on the net cash investment in the lease in each period. The amounts due from lessees under finance leases are recorded in the balance sheet as a debtor at the amount of the net investment in the lease after making provisions for bad and doubtful rentals receivable.
Investments
Investments in subsidiary and associated undertakings and joint ventures are stated in the balance sheet of the parent company at cost, or nominal value of shares issued as consideration where applicable, less provision for any impairment in value. The group profit and loss account includes the group’s share of the operating profits less losses, net interest charge and taxation of associated undertakings and joint ventures. The group balance sheet includes the investment in associated undertakings and joint ventures at the group’s share of their net assets. Other fixed asset investments are carried at cost less provision for impairment in value.
Own shares held under trust
Own shares held under trust have been deducted in arriving at shareholders’ funds in accordance with Urgent Issues Task Force Abstract 38 ‘Accounting for ESOP trusts’ (“UITF 38”). Purchases and sales of own shares are disclosed as changes in shareholders’ funds. Previously own shares were presented as fixed asset investments. The effect of this change in accounting policy on the net assets for the previous financial year is disclosed in Note 17. Comparative figures have been restated in the Balance Sheet, Cash Flow Statement and related Notes. The implementation of UITF 38 had no impact on the group’s previously reported profits and losses.
Revised UITF 17 ‘Employee share schemes’ (“Revised UITF 17”) has also been adopted in the year, which requires that the profit and loss account charge be determined as the intrinsic value of the share options granted. Previously this charge was based on either the intrinsic value or, where purchases of shares were made by an ESOP trust at fair value, by reference to the cost of shares available for the award less any contributions payable by the employees. The implementation of Revised UITF 17 had no impact on the group’s previously reported profits and losses.
The group has taken advantage of the exemption within UITF Abstract 17 not to apply its requirements to Inland Revenue approved savings-related share option schemes and equivalent overseas schemes.
Long Term Incentive Plan (“LTIP”)
Shares in the company purchased for the LTIP are held under trust. The cost of awards made by the trust under the LTIP, being the difference between the fair value of the shares and the option price at the date of grant, is taken to the profit and loss account on a straight line basis over the period in which performance is measured.
Stocks
Stocks are valued at the lower of average cost and net realisable value.
US regulatory assets
Statement of Financial Accounting Standard No. 71 ‘Accounting for the Effects of Certain Types of Regulation’ (“FAS 71”) establishes US GAAP for utilities in the US whose regulators have the power to approve and/or regulate rates that may be charged to customers. FAS 71 provides that regulatory assets may be capitalised if it is probable that future revenue in an amount at least equal to the capitalised costs will result from the inclusion of that cost in allowable costs for ratemaking purposes. Due to the different regulatory environment, no equivalent GAAP applies in the UK.
Under UK GAAP, the group’s policy is to recognise regulatory assets established in accordance with FAS 71 only where they comprise rights or other access to future economic benefits which have arisen as a result of past transactions or events which have created an obligation to transfer economic benefits to a third party. Measurement of the past transaction or
88 ScottishPower Annual Report and Accounts 2003/04
event and hence the regulatory asset, is determined in accordance with UK GAAP.
Grants and contributions
Capital grants and customer contributions in respect of additions to fixed assets are treated as deferred income and released to the profit and loss account over the estimated operational lives of the related assets.
Pensions
The group provides pension benefits through both defined benefit and defined contribution arrangements. The regular cost of providing pensions and related benefits and any variations from regular cost arising from the actuarial valuations for defined benefit schemes are charged to the profit and loss account over the expected remaining service lives of current employees following consultations with the actuary. Any difference between the charge to the profit and loss account and the actual contributions paid to the pension schemes is included as an asset or liability in the balance sheet. Payments to defined contribution schemes are charged against profits as incurred.
Post-retirement benefits other than pensions
Certain additional post-retirement benefits, principally healthcare benefits, are provided to eligible retirees within the group’s US businesses. The estimated cost of providing such benefits is charged against profits on a systematic basis over the employees’ working lives within the group.
Environmental liabilities
Provision for environmental liabilities is made when expenditure on remedial work is probable and the group is obliged, either legally or constructively through its environmental policies, to undertake such work. Where the amount is expected to be incurred over the long-term, the amount recognised is the present value of the estimated future expenditure and the unwinding of the discount is included within net interest and similar charges.
Foreign currencies
Group The results and cash flows of overseas subsidiaries are translated to sterling at the average rate of exchange for each quarter of the financial year. The net assets of such subsidiaries and the goodwill arising on their acquisition are translated to sterling at the closing rates of exchange ruling at the balance sheet date. Exchange differences which relate to the translation of overseas subsidiaries and of matching foreign currency borrowings and derivatives are taken directly to group reserves and are shown in the statement of total recognised gains and losses.
Company Transactions in foreign currencies are recorded at the rate ruling at the date of the transaction. At the year end, monetary assets and liabilities denominated in foreign currencies are translated at the rate of exchange ruling at the balance sheet date or, where applicable, at the hedged contracted rate. Any gain or loss arising on the restatement of such balances is taken to the profit and loss account.
Exchange rates
The exchange rates applied in the preparation of the Accounts were as follows:
| Year ended 31 March |
||||||||||||
| 2004 |
2003 |
2002 |
||||||||||
| Average rate for quarters ended: |
||||||||||||
| 30 June |
$ | 1.62/ | £ | $ | 1.46/ | £ | $ | 1.42/ | £ | |||
| 30 September |
$ | 1.61/ | £ | $ | 1.55/ | £ | $ | 1.44/ | £ | |||
| 31 December |
$ | 1.71/ | £ | $ | 1.57/ | £ | $ | 1.44/ | £ | |||
| 31 March |
$ | 1.84/ | £ | $ | 1.60/ | £ | $ | 1.43/ | £ | |||
| Closing rate as at 31 March |
$ | 1.84/ | £ | $ | 1.58/ | £ | $ | 1.42/ | £ | |||
A glossary of terms used in the Accounts and their US equivalents is set out on page 149.
ScottishPower Annual Report and Accounts 2003/04 89
Accounts 2003/04
for the years ended 31 March 2004 and 31 March 2003
| Year ended 31 March | ||||||||||||||
| Continuing Total 2004 |
Continuing operations 2003 |
Discontinued operations 2003 |
Total 2003 |
|||||||||||
| Notes |
£m |
£m |
£m |
£m |
||||||||||
| Turnover: group and share of joint ventures and associates |
5,828.9 | 5,273.1 | 26.7 | 5,299.8 | ||||||||||
| Less: share of turnover in joint ventures |
(31.0 | ) | (25.2 | ) | — | (25.2 | ) | |||||||
| Less: share of turnover in associates |
(0.8 | ) | (0.8 | ) | — | (0.8 | ) | |||||||
| Group turnover |
1 | 5,797.1 | 5,247.1 | 26.7 | 5,273.8 | |||||||||
| Cost of sales |
(3,630.6 | ) | (3,215.4 | ) | (11.4 | ) | (3,226.8 | ) | ||||||
| Gross profit |
2,166.5 | 2,031.7 | 15.3 | 2,047.0 | ||||||||||
| Transmission and distribution costs |
(544.5 | ) | (512.6 | ) | — | (512.6 | ) | |||||||
| Administrative expenses (including goodwill amortisation) |
(626.2 | ) | (613.2 | ) | (1.3 | ) | (614.5 | ) | ||||||
| Other operating income |
26.8 | 26.0 | — | 26.0 | ||||||||||
| Operating profit before goodwill amortisation |
1,150.6 | 1,070.9 | 14.0 | 1,084.9 | ||||||||||
| Goodwill amortisation |
(128.0 | ) | (139.0 | ) | — | (139.0 | ) | |||||||
| Operating profit |
1, 2 | 1,022.6 | 931.9 | 14.0 | 945.9 | |||||||||
| Share of operating profit in joint ventures |
7.3 | 4.8 | — | 4.8 | ||||||||||
| Share of operating profit in associates |
0.3 | 0.4 | — | 0.4 | ||||||||||
| Profit on ordinary activities before interest |
1,030.2 | 937.1 | 14.0 | 951.1 | ||||||||||
| Net interest and similar charges |
||||||||||||||
| – Group |
(232.3 | ) | (245.9 | ) | (3.0 | ) | (248.9 | ) | ||||||
| – Joint ventures |
(5.8 | ) | (5.4 | ) | — | (5.4 | ) | |||||||
| 5 | (238.1 | ) | (251.3 | ) | (3.0 | ) | (254.3 | ) | ||||||
| Profit on ordinary activities before goodwill amortisation and taxation |
920.1 | 824.8 | 11.0 | 835.8 | ||||||||||
| Goodwill amortisation |
(128.0 | ) | (139.0 | ) | — | (139.0 | ) | |||||||
| Profit on ordinary activities before taxation |
792.1 | 685.8 | 11.0 | 696.8 | ||||||||||
| Taxation |
||||||||||||||
| – Group |
(247.3 | ) | (205.8 | ) | (3.4 | ) | (209.2 | ) | ||||||
| – Joint ventures |
(1.0 | ) | 0.3 | — | 0.3 | |||||||||
| – Associates |
(0.1 | ) | (0.1 | ) | — | (0.1 | ) | |||||||
| 6 | (248.4 | ) | (205.6 | ) | (3.4 | ) | (209.0 | ) | ||||||
| Profit after taxation |
543.7 | 480.2 | 7.6 | 487.8 | ||||||||||
| Minority interests (including non-equity) |
27 | (5.8 | ) | (5.2 | ) | — | (5.2 | ) | ||||||
| Profit for the financial year |
537.9 | 475.0 | 7.6 | 482.6 | ||||||||||
| Dividends |
8 | (375.1 | ) | (529.5 | ) | — | (529.5 | ) | ||||||
| Profit/(loss) retained |
26 | 162.8 | (54.5 | ) | 7.6 | (46.9 | ) | |||||||
| Earnings per ordinary share |
7 | 29.40p | 25.76p | 0.41p | 26.17p | |||||||||
| Adjusting item – goodwill amortisation |
7.00p | 7.54p | — | 7.54p | ||||||||||
| Earnings per ordinary share before goodwill amortisation |
7 | 36.40p | 33.30p | 0.41p | 33.71p | |||||||||
| Diluted earnings per ordinary share |
7 | 28.83p | 26.11p | |||||||||||
| Adjusting item – goodwill amortisation |
6.77p | 7.52p | ||||||||||||
| Diluted earnings per ordinary share before goodwill amortisation |
7 | 35.60p | 33.63p | |||||||||||
| Dividends per ordinary share |
8 | 20.50p | 28.708p | |||||||||||
The Accounting Policies and Definitions on pages 85 to 89, together with the Notes on pages 95 to 143 and 145 to 146 form part of these Accounts.
90 ScottishPower Annual Report and Accounts 2003/04
Group Profit and Loss Account
for the year ended 31 March 2002
| Year ended 31 March 2002 | |||||||||||||||||||||||
| Continuing operations 2002 |
Exceptional items- continuing operations (Note 4) 2002 |
Total continuing operations 2002 |
Discontinued operations 2002 |
Exceptional items- discontinued operations (Note 4) 2002 |
Total discontinued operations 2002 |
Total 2002 |
|||||||||||||||||
| Notes |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
||||||||||||||||
| Turnover: group and share of joint ventures and associates |
5,545.9 | — | 5,545.9 | 791.3 | — | 791.3 | 6,337.2 | ||||||||||||||||
| Less: share of turnover in joint ventures |
(22.6 | ) | — | (22.6 | ) | — | — | — | (22.6 | ) | |||||||||||||
| Less: share of turnover in associates |
(0.5 | ) | — | (0.5 | ) | — | — | — | (0.5 | ) | |||||||||||||
| Group turnover |
1 | 5,522.8 | — | 5,522.8 | 791.3 | — | 791.3 | 6,314.1 | |||||||||||||||
| Cost of sales |
(3,920.0 | ) | — | (3,920.0 | ) | (490.8 | ) | — | (490.8 | ) | (4,410.8 | ) | |||||||||||
| Gross profit |
1,602.8 | — | 1,602.8 | 300.5 | — | 300.5 | 1,903.3 | ||||||||||||||||
| Transmission and distribution costs |
(479.3 | ) | — | (479.3 | ) | (33.3 | ) | — | (33.3 | ) | (512.6 | ) | |||||||||||
| Administrative expenses (including goodwill amortisation) |
(533.8 | ) | (18.5 | ) | (552.3 | ) | (142.8 | ) | — | (142.8 | ) | (695.1 | ) | ||||||||||
| Other operating income |
64.2 | — | 64.2 | 3.6 | — | 3.6 | 67.8 | ||||||||||||||||
| Utilisation of Appliance Retailing disposal provision |
— | — | — | 13.2 | — | 13.2 | 13.2 | ||||||||||||||||
| Operating profit before goodwill amortisation |
800.5 | (18.5 | ) | 782.0 | 143.6 | — | 143.6 | 925.6 | |||||||||||||||
| Goodwill amortisation |
(146.6 | ) | — | (146.6 | ) | (2.4 | ) | — | (2.4 | ) | (149.0 | ) | |||||||||||
| Operating profit |
1,2 | 653.9 | (18.5 | ) | 635.4 | 141.2 | — | 141.2 | 776.6 | ||||||||||||||
| Share of operating profit in joint ventures |
2.2 | — | 2.2 | — | — | — | 2.2 | ||||||||||||||||
| Share of operating profit in associates |
0.2 | — | 0.2 | — | — | — | 0.2 | ||||||||||||||||
| 656.3 | (18.5 | ) | 637.8 | 141.2 | — | 141.2 | 779.0 | ||||||||||||||||
| Loss on disposal of and withdrawal from Appliance Retailing before goodwill write back |
4 | — | — | — | — | (105.0 | ) | (105.0 | ) | (105.0 | ) | ||||||||||||
| Goodwill write back |
4 | — | — | — | — | (15.1 | ) | (15.1 | ) | (15.1 | ) | ||||||||||||
| Loss on disposal of and withdrawal from Appliance Retailing |
4 | — | — | — | — | (120.1 | ) | (120.1 | ) | (120.1 | ) | ||||||||||||
| Provision for loss on disposal of Southern Water before goodwill write back |
4 | — | — | — | — | (449.3 | ) | (449.3 | ) | (449.3 | ) | ||||||||||||
| Goodwill write back |
4 | — | — | — | — | (738.2 | ) | (738.2 | ) | (738.2 | ) | ||||||||||||
| Provision for loss on disposal of Southern Water |
4 | — | — | — | — | (1,187.5 | ) | (1,187.5 | ) | (1,187.5 | ) | ||||||||||||
| Profit/(loss) on ordinary activities before interest |
656.3 | (18.5 | ) | 637.8 | 141.2 | (1,307.6 | ) | (1,166.4 | ) | (528.6 | ) | ||||||||||||
| Net interest and similar charges |
|||||||||||||||||||||||
| – Group before exceptional interest and similar charges |
(336.3 | ) | — | (336.3 | ) | (36.9 | ) | — | (36.9 | ) | (373.2 | ) | |||||||||||
| – Exceptional interest and similar charges |
4 | — | (18.8 | ) | (18.8 | ) | — | (12.0 | ) | (12.0 | ) | (30.8 | ) | ||||||||||
| – Joint ventures |
(6.2 | ) | — | (6.2 | ) | — | — | — | (6.2 | ) | |||||||||||||
| 5 | (342.5 | ) | (18.8 | ) | (361.3 | ) | (36.9 | ) | (12.0 | ) | (48.9 | ) | (410.2 | ) | |||||||||
| Profit/(loss) on ordinary activities before goodwill amortisation and taxation |
460.4 | (37.3 | ) | 423.1 | 106.7 | (1,319.6 | ) | (1,212.9 | ) | (789.8 | ) | ||||||||||||
| Goodwill amortisation |
(146.6 | ) | — | (146.6 | ) | (2.4 | ) | — | (2.4 | ) | (149.0 | ) | |||||||||||
| Profit/(loss) on ordinary activities before taxation |
313.8 | (37.3 | ) | 276.5 | 104.3 | (1,319.6 | ) | (1,215.3 | ) | (938.8 | ) | ||||||||||||
| Taxation |
|||||||||||||||||||||||
| – Group before tax on exceptional items |
(68.0 | ) | — | (68.0 | ) | (55.1 | ) | — | (55.1 | ) | (123.1 | ) | |||||||||||
| – Tax on exceptional items |
4 | — | 11.3 | 11.3 | — | 27.5 | 27.5 | 38.8 | |||||||||||||||
| – Joint ventures |
1.1 | — | 1.1 | — | — | — | 1.1 | ||||||||||||||||
| 6 | (66.9 | ) | 11.3 | (55.6 | ) | (55.1 | ) | 27.5 | (27.6 | ) | (83.2 | ) | |||||||||||
| Profit/(loss) after taxation |
246.9 | (26.0 | ) | 220.9 | 49.2 | (1,292.1 | ) | (1,242.9 | ) | (1,022.0 | ) | ||||||||||||
| Minority interests (including non-equity) |
(6.9 | ) | — | (6.9 | ) | 41.8 | — | 41.8 | 34.9 | ||||||||||||||
| Profit/(loss) for the financial year |
240.0 | (26.0 | ) | 214.0 | 91.0 | (1,292.1 | ) | (1,201.1 | ) | (987.1 | ) | ||||||||||||
| Dividends |
|||||||||||||||||||||||
| – Cash |
8 | (503.5 | ) | — | (503.5 | ) | — | — | — | (503.5 | ) | ||||||||||||
| – Dividend in specie on demerger of Thus |
8 | — | — | — | (436.6 | ) | — | (436.6 | ) | (436.6 | ) | ||||||||||||
| (503.5 | ) | — | (503.5 | ) | (436.6 | ) | — | (436.6 | ) | (940.1 | ) | ||||||||||||
| Loss retained |
26 | (263.5 | ) | (26.0 | ) | (289.5 | ) | (345.6 | ) | (1,292.1 | ) | (1,637.7 | ) | (1,927.2 | ) | ||||||||
| Earnings/(loss) per ordinary share |
7 | 13.06 | p | (1.41 | )p | 11.65 | p | 4.95 | p | (70.31 | )p | (65.36 | )p | (53.71 | )p | ||||||||
| Adjusting items – exceptional items |
— | 1.41 | p | 1.41 | p | — | 70.31 | p | 70.31 | p | 71.72 | p | |||||||||||
| – goodwill amortisation |
7.98 | p | — | 7.98 | p | 0.13 | p | — | 0.13 | p | 8.11 | p | |||||||||||
| Earnings per ordinary share before exceptional items and goodwill amortisation |
7 | 21.04 | p | — | 21.04 | p | 5.08 | p | — | 5.08 | p | 26.12 | p | ||||||||||
| Diluted loss per ordinary share |
7 | (53.64 | )p | ||||||||||||||||||||
| Adjusting items – exceptional items |
71.63 | p | |||||||||||||||||||||
| – goodwill amortisation |
8.10 | p | |||||||||||||||||||||
| Diluted earnings per ordinary share before exceptional items and goodwill amortisation |
7 | 26.09 | p | ||||||||||||||||||||
| Cash dividends per ordinary share |
8 | 27.34 | p | ||||||||||||||||||||
The Accounting Policies and Definitions on pages 85 to 89, together with the Notes on pages 95 to 143 and 145 to 146 form part of these Accounts.
ScottishPower Annual Report and Accounts 2003/04 91
Accounts 2003/04
Statement of Total Recognised Gains and Losses
for the year ended 31 March 2004
| 2004 | 2003 | 2002 | |||||||||
| Note |
£m |
£m |
£m |
||||||||
| Profit/(loss) for the financial year |
537.9 | 482.6 | (987.1 | ) | |||||||
| Exchange movement on translation of overseas results and net assets |
26 | (537.6 | ) | (387.0 | ) | (4.2 | ) | ||||
| Translation differences on foreign currency hedging |
26 | 475.2 | 357.6 | (19.5 | ) | ||||||
| Tax on translation differences on foreign currency hedging |
26 | 46.1 | (28.8 | ) | — | ||||||
| Unrealised gains on fixed asset disposals |
26 | — | — | 4.9 | |||||||
| Total recognised gains and losses for the financial year |
521.6 | 424.4 | (1,005.9 | ) | |||||||
Note of Historical Cost Profits and Losses
for the year ended 31 March 2004
| 2004 | 2003 | 2002 | ||||||||
| Note |
£m |
£m |
£m |
|||||||
| Profit/(loss) on ordinary activities before taxation |
792.1 | 696.8 | (938.8 | ) | ||||||
| Differences between historical cost depreciation charge and actual depreciation charge for the year calculated on the revalued amount of fixed assets |
26 | 1.9 | 2.0 | 3.4 | ||||||
| Fixed asset revaluation gains realised on disposal |
26 | — | — | 168.2 | ||||||
| Historical cost profit/(loss) on ordinary activities before taxation |
794.0 | 698.8 | (767.2 | ) | ||||||
| Historical cost profit/(loss) retained for the financial year after taxation, minority interest and dividends |
164.7 | (44.9 | ) | (1,755.6 | ) | |||||
Reconciliation of Movements in Shareholders’ Funds
for the year ended 31 March 2004
| 2004 | 2003 | 2002 | |||||||
| (As restated – Note 17) | |||||||||
| £m |
£m |
£m |
|||||||
| Profit/(loss) for the financial year |
537.9 | 482.6 | (987.1 | ) | |||||
| Dividends |
|||||||||
| – Cash |
(375.1 | ) | (529.5 | ) | (503.5 | ) | |||
| – Dividend in specie on demerger of Thus |
— | — | (436.6 | ) | |||||
| Profit/(loss) retained |
162.8 | (46.9 | ) | (1,927.2 | ) | ||||
| Exchange movement on translation of overseas results and net assets |
(537.6 | ) | (387.0 | ) | (4.2 | ) | |||
| Translation differences on foreign currency hedging |
475.2 | 357.6 | (19.5 | ) | |||||
| Tax on translation differences on foreign currency hedging |
46.1 | (28.8 | ) | — | |||||
| Unrealised gains on fixed asset disposals |
— | — | 4.9 | ||||||
| Share capital issued |
13.1 | 12.0 | 16.2 | ||||||
| Consideration paid in respect of purchase of own shares held under trust |
(28.9 | ) | (36.2 | ) | (25.6 | ) | |||
| Credit in respect of employee share awards |
4.9 | 10.0 | 2.5 | ||||||
| Consideration received in respect of sale of own shares held under trust |
0.4 | 6.4 | 19.8 | ||||||
| Goodwill realised on disposals |
— | — | 753.3 | ||||||
| Goodwill realised on demerger of Thus |
— | — | 14.7 | ||||||
| Net movement in shareholders’ funds |
136.0 | (112.9 | ) | (1,165.1 | ) | ||||
| Opening shareholders’ funds (as restated for implementation of UITF 38 ‘Accounting for ESOP trusts’) |
4,554.9 | 4,667.8 | 5,832.9 | ||||||
| Closing shareholders’ funds |
4,690.9 | 4,554.9 | 4,667.8 | ||||||
The Accounting Policies and Definitions on pages 85 to 89, together with the Notes on pages 95 to 143 and 145 to 146 form part of these Accounts.
92 ScottishPower Annual Report and Accounts 2003/04
for the year ended 31 March 2004
| 2004 | 2003 | 2002 | |||||||||
| (As restated – Note 17) | |||||||||||
| Notes |
£m |
£m |
£m |
||||||||
| Cash inflow from operating activities |
9 | 1,364.0 | 1,412.9 | 1,248.4 | |||||||
| Dividends received from joint ventures |
0.5 | 0.9 | 0.3 | ||||||||
| Returns on investments and servicing of finance |
10(a) | (210.0 | ) | (297.0 | ) | (377.8 | ) | ||||
| Taxation |
(121.8 | ) | (191.3 | ) | (85.0 | ) | |||||
| Free cash flow |
1,032.7 | 925.5 | 785.9 | ||||||||
| Capital expenditure and financial investment |
10(b) | (831.2 | ) | (675.1 | ) | (1,142.5 | ) | ||||
| Cash flow before acquisitions and disposals |
201.5 | 250.4 | (356.6 | ) | |||||||
| Acquisitions and disposals |
10(c) | (31.3 | ) | 1,799.0 | 150.0 | ||||||
| Equity dividends paid |
(394.4 | ) | (523.4 | ) | (496.8 | ) | |||||
| Cash (outflow)/inflow before use of liquid resources and financing |
(224.2 | ) | 1,526.0 | (703.4 | ) | ||||||
| Management of liquid resources |
10(d),13 | (354.1 | ) | (161.1 | ) | (38.7 | ) | ||||
| Financing |
|||||||||||
| – Issue of ordinary share capital |
10(e) | 13.1 | 12.0 | 16.2 | |||||||
| – Redemption of preferred stock of PacifiCorp |
10(e) | (4.6 | ) | (5.1 | ) | (69.5 | ) | ||||
| – Cancellation of cross-currency swaps |
10(e) | 76.1 | — | — | |||||||
| – Repricing of cross-currency swaps |
10(e) | 403.0 | — | — | |||||||
| – Net purchase of own shares held under trust |
10(e) | (28.5 | ) | (29.8 | ) | (5.8 | ) | ||||
| – Increase/(decrease) in debt |
10(e),13 | 464.3 | (1,191.4 | ) | 982.4 | ||||||
| 923.4 | (1,214.3 | ) | 923.3 | ||||||||
| Increase in cash in year |
13 | 345.1 | 150.6 | 181.2 | |||||||
Free cash flow represents cash flow from operating activities after adjusting for dividends received from joint ventures, returns on investments and servicing of finance and taxation.
Reconciliation of Net Cash Flow to Movement in Net Debt
for the year ended 31 March 2004
| 2004 | 2003 | 2002 | |||||||||
| Note |
£m |
£m |
£m |
||||||||
| Increase in cash in year |
345.1 | 150.6 | 181.2 | ||||||||
| Cash (inflow)/outflow from (increase)/decrease in debt |
(464.3 | ) | 1,191.4 | (982.4 | ) | ||||||
| Cash outflow from movement in liquid resources |
354.1 | 161.1 | 38.7 | ||||||||
| Change in net debt resulting from cash flows |
234.9 | 1,503.1 | (762.5 | ) | |||||||
| Net debt/(funds) disposed |
— | 100.0 | (46.9 | ) | |||||||
| Foreign exchange movement |
388.3 | 289.9 | (6.3 | ) | |||||||
| Other non-cash movements |
(26.7 | ) | (5.6 | ) | (107.6 | ) | |||||
| Movement in net debt in year |
596.5 | 1,887.4 | (923.3 | ) | |||||||
| Net debt at end of previous year |
(4,321.0 | ) | (6,208.4 | ) | (5,285.1 | ) | |||||
| Net debt at end of year |
13 | (3,724.5 | ) | (4,321.0 | ) | (6,208.4 | ) | ||||
The Accounting Policies and Definitions on pages 85 to 89, together with the Notes on pages 95 to 143 and 145 to 146 form part of these Accounts.
ScottishPower Annual Report and Accounts 2003/04 93
Accounts 2003/04
as at 31 March 2004
| 2004 | 2003 (As restated – Note 17) |
|||||||
| Notes |
£m |
£m |
||||||
| Fixed assets |
||||||||
| Intangible assets |
15 | 1,855.9 | 2,280.6 | |||||
| Tangible assets |
16 | 8,756.6 | 9,028.7 | |||||
| Investments |
||||||||
| – Investments in joint ventures: |
||||||||
| Share of gross assets |
180.8 | 111.9 | ||||||
| Share of gross liabilities |
(157.3 | ) | (111.8 | ) | ||||
| 23.5 | 0.1 | |||||||
| – Loans to joint ventures |
38.8 | 40.2 | ||||||
| 62.3 | 40.3 | |||||||
| – Investments in associates |
2.7 | 2.8 | ||||||
| – Other investments |
129.8 | 150.2 | ||||||
| 17 | 194.8 | 193.3 | ||||||
| 10,807.3 | 11,502.6 | |||||||
| Current assets |
||||||||
| Stocks |
18 | 185.5 | 154.6 | |||||
| Debtors |
||||||||
| – Gross debtors |
1,576.2 | 1,684.5 | ||||||
| – Less non-recourse financing |
(109.5 | ) | (148.2 | ) | ||||
| 19 | 1,466.7 | 1,536.3 | ||||||
| Short-term bank and other deposits |
1,347.3 | 664.6 | ||||||
| 2,999.5 | 2,355.5 | |||||||
| Creditors: amounts falling due within one year |
||||||||
| Loans and other borrowings |
20 | (410.7 | ) | (208.5 | ) | |||
| Other creditors |
21 | (1,658.7 | ) | (1,777.3 | ) | |||
| (2,069.4 | ) | (1,985.8 | ) | |||||
| Net current assets |
930.1 | 369.7 | ||||||
| Total assets less current liabilities |
11,737.4 | 11,872.3 | ||||||
| Creditors: amounts falling due after more than one year |
||||||||
| Loans and other borrowings (including convertible bonds) |
20 | (4,661.1 | ) | (4,777.1 | ) | |||
| Provisions for liabilities and charges |
||||||||
| – Deferred tax |
22 | (1,242.2 | ) | (1,301.9 | ) | |||
| – Other provisions |
23 | (504.5 | ) | (605.6 | ) | |||
| (1,746.7 | ) | (1,907.5 | ) | |||||
| Deferred income |
24 | (577.8 | ) | (558.9 | ) | |||
| Net assets |
14 | 4,751.8 | 4,628.8 | |||||
| Called up share capital |
25,26 | 929.8 | 928.0 | |||||
| Share premium |
26 | 2,275.7 | 2,264.4 | |||||
| Revaluation reserve |
26 | 41.6 | 43.5 | |||||
| Capital redemption reserve |
26 | 18.3 | 18.3 | |||||
| Merger reserve |
26 | 406.4 | 406.4 | |||||
| Profit and loss account |
26 | 1,019.1 | 894.3 | |||||
| Equity shareholders’ funds |
26 | 4,690.9 | 4,554.9 | |||||
| Minority interests (including non-equity) |
27 | 60.9 | 73.9 | |||||
| Capital employed |
4,751.8 | 4,628.8 | ||||||
| Net asset value per ordinary share |
14 | 256.2p | 248.4p | |||||
Approved by the Board on 25 May 2004 and signed on its behalf by
| /s/ Charles Miller Smith |
/s/ David Nish | |||
| Charles Miller Smith | David Nish | |||
| Chairman |
Finance Director | |||
The Accounting Policies and Definitions on pages 85 to 89, together with the Notes on pages 95 to 143 and 145 to 146 form part of these Accounts.
94 ScottishPower Annual Report and Accounts 2003/04
for the year ended 31 March 2004
1 Segmental profit and loss information
(a) Turnover by segment
| Total turnover | Inter-segment turnover | External turnover | ||||||||||||||||||||||
| 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||
| Note |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
£m | |||||||||||||||
| United Kingdom – continuing operations |
||||||||||||||||||||||||
| UK Division – Integrated Generation and Supply |
2,804.0 | 2,180.8 | 2,160.7 | (26.6 | ) | (33.0 | ) | (39.3 | ) | 2,777.4 | 2,147.8 | 2,121.4 | ||||||||||||
| Infrastructure Division – Power Systems |
704.1 | 667.3 | 646.6 | (345.8 | ) | (353.3 | ) | (399.0 | ) | 358.3 | 314.0 | 247.6 | ||||||||||||
| United Kingdom total – continuing operations |
3,135.7 | 2,461.8 | 2,369.0 | |||||||||||||||||||||
| United States – continuing operations |
||||||||||||||||||||||||
| PacifiCorp |
2,321.1 | 2,502.2 | 2,980.7 | (2.5 | ) | (2.8 | ) | – | 2,318.6 | 2,499.4 | 2,980.7 | |||||||||||||
| PPM |
352.9 | 293.6 | 173.1 | (10.1 | ) | (7.7 | ) | – | 342.8 | 285.9 | 173.1 | |||||||||||||
| United States total – continuing operations |
2,661.4 | 2,785.3 | 3,153.8 | |||||||||||||||||||||
| Total continuing operations |
5,797.1 | 5,247.1 | 5,522.8 | |||||||||||||||||||||
| United Kingdom – discontinued operations |
||||||||||||||||||||||||
| Southern Water |
– | 26.7 | 430.6 | – | – | (0.7 | ) | – | 26.7 | 429.9 | ||||||||||||||
| Thus |
– | – | 257.8 | – | – | (28.7 | ) | – | – | 229.1 | ||||||||||||||
| Appliance Retailing |
– | – | 133.9 | – | – | (1.6 | ) | – | – | 132.3 | ||||||||||||||
| United Kingdom total – discontinued operations |
– | 26.7 | 791.3 | |||||||||||||||||||||
| Total |
(i | ) | 5,797.1 | 5,273.8 | 6,314.1 | |||||||||||||||||||
| (i) | In the segmental analysis turnover is shown by geographical origin. Turnover analysed by geographical destination is not materially different. |
(b) Operating profit/(loss) by segment
| Before goodwill amortisation 2004 |
Goodwill amortisation 2004 |
2004 | Before goodwill amortisation 2003 |
Goodwill amortisation 2003 |
2003 | Before goodwill amortisation and exceptional 2002 |
Goodwill amortisation 2002 |
Exceptional item 2002 |
2002 | |||||||||||||||||
| £m |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
|||||||||||||||||
| United Kingdom – continuing operations |
||||||||||||||||||||||||||
| UK Division – Integrated Generation and Supply |
101.0 | (4.9 | ) | 96.1 | 77.9 | (4.9 | ) | 73.0 | 78.7 | (4.9 | ) | (18.5 | ) | 55.3 | ||||||||||||
| Infrastructure Division – Power Systems |
393.6 | – | 393.6 | 367.8 | – | 367.8 | 354.9 | – | – | 354.9 | ||||||||||||||||
| United Kingdom total – continuing operations |
494.6 | (4.9 | ) | 489.7 | 445.7 | (4.9 | ) | 440.8 | 433.6 | (4.9 | ) | (18.5 | ) | 410.2 | ||||||||||||
| United States – continuing operations |
||||||||||||||||||||||||||
| PacifiCorp |
619.3 | (122.5 | ) | 496.8 | 596.7 | (133.9 | ) | 462.8 | 371.6 | (141.7 | ) | – | 229.9 | |||||||||||||
| PPM |
36.7 | (0.6 | ) | 36.1 | 28.5 | (0.2 | ) | 28.3 | (4.7 | ) | – | – | (4.7 | ) | ||||||||||||
| United States total – continuing operations |
656.0 | (123.1 | ) | 532.9 | 625.2 | (134.1 | ) | 491.1 | 366.9 | (141.7 | ) | – | 225.2 | |||||||||||||
| Total continuing operations |
1,150.6 | (128.0 | ) | 1,022.6 | 1,070.9 | (139.0 | ) | 931.9 | 800.5 | (146.6 | ) | (18.5 | ) | 635.4 | ||||||||||||
| United Kingdom – discontinued operations |
||||||||||||||||||||||||||
| Southern Water |
– | – | – | 14.0 | – | 14.0 | 216.3 | – | – | 216.3 | ||||||||||||||||
| Thus |
– | – | – | – | – | – | (63.7 | ) | (2.4 | ) | – | (66.1 | ) | |||||||||||||
| Appliance Retailing |
– | – | – | – | – | – | (9.0 | ) | – | – | (9.0 | ) | ||||||||||||||
| United Kingdom total – discontinued operations |
– | – | – | 14.0 | – | 14.0 | 143.6 | (2.4 | ) | – | 141.2 | |||||||||||||||
| Total |
1,150.6 | (128.0 | ) | 1,022.6 | 1,084.9 | (139.0 | ) | 945.9 | 944.1 | (149.0 | ) | (18.5 | ) | 776.6 | ||||||||||||
ScottishPower Annual Report and Accounts 2003/04 95
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
1 Segmental profit and loss information continued
(c) Depreciation and impairment by segment
| Depreciation 2004 |
Depreciation 2003 |
Depreciation 2002 |
Impairment 2002 |
Total 2002 | ||||||
| £m |
£m |
£m |
£m |
£m | ||||||
| United Kingdom – continuing operations |
||||||||||
| UK Division – Integrated Generation and Supply |
88.5 | 87.3 | 72.9 | 13.0 | 85.9 | |||||
| Infrastructure Division – Power Systems |
109.1 | 112.4 | 108.3 | – | 108.3 | |||||
| United Kingdom total – continuing operations |
197.6 | 199.7 | 181.2 | 13.0 | 194.2 | |||||
| United States – continuing operations |
||||||||||
| PacifiCorp |
230.1 | 233.9 | 225.4 | – | 225.4 | |||||
| PPM |
11.0 | 8.0 | 2.4 | – | 2.4 | |||||
| United States total – continuing operations |
241.1 | 241.9 | 227.8 | – | 227.8 | |||||
| Total continuing operations |
438.7 | 441.6 | 409.0 | 13.0 | 422.0 | |||||
| United Kingdom – discontinued operations |
||||||||||
| Southern Water |
– | 5.6 | 77.6 | – | 77.6 | |||||
| Thus |
– | – | 65.2 | – | 65.2 | |||||
| Appliance Retailing |
– | – | 3.2 | – | 3.2 | |||||
| United Kingdom total – discontinued operations |
– | 5.6 | 146.0 | – | 146.0 | |||||
| Total depreciation and impairment charged to operating profit |
438.7 | 447.2 | 555.0 | 13.0 | 568.0 | |||||
| Impairment within loss on disposal of and withdrawal from Appliance Retailing |
– | – | – | 32.2 | 32.2 | |||||
| Impairment within provision for loss on disposal of Southern Water |
– | – | – | 449.3 | 449.3 | |||||
| Total depreciation and impairment |
438.7 | 447.2 | 555.0 | 494.5 | 1,049.5 | |||||
2 Operating profit
(a) Operating profit is stated after charging/(crediting):
| 2004 | 2003 | 2002 | |||||||
| £m |
£m |
£m |
|||||||
| Depreciation and impairment of tangible fixed assets |
438.7 | 447.2 | 568.0 | ||||||
| Amortisation of goodwill |
128.0 | 139.0 | 149.0 | ||||||
| Release of customer contributions/grants |
(19.5 | ) | (18.6 | ) | (17.8 | ) | |||
| Research and development |
0.2 | 0.7 | 3.1 | ||||||
| Hire of plant and equipment – operating leases |
0.1 | 0.1 | 0.1 | ||||||
| Hire of other assets – operating leases |
16.2 | 14.6 | 55.6 | ||||||
Operating profit for the years ended 31 March 2004, 31 March 2003 and 31 March 2002 is also stated after (crediting)/charging £(2.9) million, £27.8 million and £(4.2) million respectively in relation to finance leases in the US, which are financed by non-recourse borrowings and qualify for linked presentation under FRS 5. Net earnings comprise gross (earnings)/loss, after provision against the carrying value of the group’s residual interests, of £(32.4) million, £3.2 million and £(32.3) million less finance costs of £29.5 million, £24.6 million and £28.1 million respectively.
(b) Auditors’ remuneration*
| 2004 | 2003 | 2002 | |||||||
| Note |
£m |
£m |
£m | ||||||
| Audit services |
|||||||||
| – statutory audit |
1.5 | 1.5 | 1.5 | ||||||
| – audit-related regulatory reporting |
0.4 | 0.6 | 0.7 | ||||||
| Further assurance services |
0.7 | 0.7 | 3.2 | ||||||
| Tax services |
|||||||||
| – compliance services |
1.6 | 1.6 | 1.6 | ||||||
| – advisory services |
0.8 | 3.2 | 3.6 | ||||||
| Other services |
(i | ) | – | 0.3 | 7.5 | ||||
| Total UK and US audit and non-audit fees paid to auditors |
5.0 | 7.9 | 18.1 | ||||||
| * | Following the release of recent guidance issued by the Institute of Chartered Accountants in England & Wales the presentation of Auditors’ remuneration in the above table has been amended for all years. |
The Audit Committee and the firm of external auditors have safeguards to avoid the possibility that the auditors’ objectivity and independence could be compromised. These safeguards include the adoption by the Committee of a policy regarding pre-approval of audit and permitted non-statutory audit services provided by the external auditors and a policy on the hiring of external audit staff.
Where it is deemed that the work to be undertaken is of a nature that is generally considered reasonable to be completed by the auditor of the group for sound commercial and practical reasons, including confidentiality, the conduct of such work will be permissible provided that it has been pre-approved by the Audit Committee. Examples of pre-approved services include the completion of regulatory audits, provision of taxation and regulatory advice, reporting in relation to the Securities and Exchange Commission and the UK Listing Authority requirements and the completion of certain financial due diligence work. All these services are also subject to a pre-defined fee limit. Any work performed in excess of this limit must be approved by the Finance Director and the Chairman of the Audit Committee.
Fees and expenses invoiced by the auditors for non-statutory audit services include £1.5 million (2003 £2.3 million, 2002 £10.4 million) payable in the UK.
| (i) | Fees for Other services for the year ended 31 March 2003 included an amount of £0.3 million which was paid to PricewaterhouseCoopers Consulting in the period prior to its disposal by PricewaterhouseCoopers on 2 October 2002. |
For the years ended 31 March 2004 and 31 March 2003, all of the above non-statutory audit fees were charged to operating profit.
For the year ended 31 March 2002, £15.1 million of the above non-statutory audit fees were charged to operating profit, £0.6 million were charged to exceptional loss on disposal of and withdrawal from Appliance Retailing and £0.9 million were charged to exceptional provision for loss on disposal of Southern Water.
96 ScottishPower Annual Report and Accounts 2003/04
3 Employee information
(a) Employee costs
| 2004 | 2003 | 2002 | ||||||||||
| Note |
£m |
£m |
£m |
|||||||||
| Wages and salaries |
525.6 | 553.1 | 695.6 | |||||||||
| Social security costs |
35.7 | 36.7 | 46.9 | |||||||||
| Pension and other costs |
(i | ) | 98.1 | 68.0 | 43.9 | |||||||
| Total employee costs |
659.4 | 657.8 | 786.4 | |||||||||
| Less: charged as capital expenditure |
(161.6 | ) | (155.2 | ) | (191.3 | ) | ||||||
| Charged to the profit and loss account |
497.8 | 502.6 | 595.1 | |||||||||
| (i) | Pension costs above comprise pension costs, company contributions to the PacifiCorp 401(k) plan and costs of other post-retirement and other post-employment benefits. The cost of the group’s pension arrangements for the year ended 31 March 2004 was £66.7 million (2003 £41.8 million, 2002 £21.4 million). |
(b) Employee numbers
The year end and average numbers of employees (full-time and part-time) employed by the group, including executive directors, were:
| At 31 March | Annual average | ||||||||||||||
| Note |
2004 |
2003 |
2002 |
2004 |
2003 |
2002 | |||||||||
| United Kingdom – continuing operations |
|||||||||||||||
| UK Division – Integrated Generation and Supply |
4,793 | 4,319 | 4,582 | 4,523 | 4,362 | 4,589 | |||||||||
| Infrastructure Division – Power Systems |
3,324 | 3,215 | 3,084 | 3,256 | 3,238 | 3,174 | |||||||||
| United Kingdom total – continuing operations |
8,117 | 7,534 | 7,666 | 7,779 | 7,600 | 7,763 | |||||||||
| United States – continuing operations |
|||||||||||||||
| PacifiCorp |
6,510 | 6,130 | 6,289 | 6,339 | 6,175 | 6,436 | |||||||||
| PPM |
194 | 161 | 98 | 180 | 128 | 76 | |||||||||
| United States total – continuing operations |
6,704 | 6,291 | 6,387 | 6,519 | 6,303 | 6,512 | |||||||||
| Total continuing operations |
14,821 | 13,825 | 14,053 | 14,298 | 13,903 | 14,275 | |||||||||
| United Kingdom – discontinued operations |
|||||||||||||||
| Southern Water |
– | – | 2,109 | – | 2,024 | 2,125 | |||||||||
| Thus |
– | – | – | – | – | 2,392 | |||||||||
| Appliance Retailing |
– | – | – | – | – | 2,391 | |||||||||
| United Kingdom total – discontinued operations |
(i | ) | – | – | 2,109 | – | 2,024 | 6,908 | |||||||
| Total |
14,821 | 13,825 | 16,162 | 14,298 | 15,927 | 21,183 | |||||||||
The year end and average numbers of full-time equivalent staff employed by the group, including executive directors, were:
| At 31 March | Annual average | ||||||||||||||
| Note |
2004 |
2003 |
2002 |
2004 |
2003 |
2002 | |||||||||
| United Kingdom |
|||||||||||||||
| – continuing operations |
7,736 | 7,163 | 7,353 | 7,413 | 7,240 | 7,391 | |||||||||
| – discontinued operations |
(i | ) | – | – | 2,056 | – | 1,982 | 6,314 | |||||||
| United States |
6,663 | 6,265 | 6,349 | 6,476 | 6,268 | 6,474 | |||||||||
| Total |
14,399 | 13,428 | 15,758 | 13,889 | 15,490 | 20,179 | |||||||||
| (i) | The annual average for 2003 for Southern Water was calculated for the period prior to disposal on 23 April 2002. The annual average for 2002 for discontinued operations was calculated for the period prior to disposal or demerger. This represented the period to 8 October 2001 for Appliance Retailing and the period to 19 March 2002 for Thus. |
(c) Directors’ remuneration
Details, for each director, of remuneration, pension entitlements and interests in share options are set out on pages 79 to 83. This information forms part of the Accounts.
ScottishPower Annual Report and Accounts 2003/04 97
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
4 Exceptional items
| Continuing operations and Total 2004 |
Continuing operations and Total 2003 |
Continuing operations 2002 |
Discontinued operations 2002 |
Total 2002 |
||||||||||||
| Notes |
£m |
£m |
£m |
£m |
£m |
|||||||||||
| (a) Recognised in arriving at operating profit |
||||||||||||||||
| Reorganisation costs |
(i | ) | – | – | (18.5 | ) | – | (18.5 | ) | |||||||
| Total recognised in arriving at operating profit |
– | – | (18.5 | ) | – | (18.5 | ) | |||||||||
| (b) Recognised after operating profit |
||||||||||||||||
| Loss on disposal of and withdrawal from Appliance Retailing |
(ii | ) | – | – | – | (120.1 | ) | (120.1 | ) | |||||||
| Provision for loss on disposal of Southern Water before goodwill write back |
(iii | ) | – | – | – | (449.3 | ) | (449.3 | ) | |||||||
| Goodwill write back relating to Southern Water |
(iii | ) | – | – | – | (738.2 | ) | (738.2 | ) | |||||||
| Total recognised after operating profit |
– | – | – | (1,307.6 | ) | (1,307.6 | ) | |||||||||
| Total exceptional items before interest and taxation |
– | – | (18.5 | ) | (1,307.6 | ) | (1,326.1 | ) | ||||||||
| Restructuring of debt portfolio |
(iv | ) | – | – | (18.8 | ) | (12.0 | ) | (30.8 | ) | ||||||
| Tax on exceptional items |
– | – | 11.3 | 27.5 | 38.8 | |||||||||||
| Total exceptional items (net of tax) |
– | – | (26.0 | ) | (1,292.1 | ) | (1,318.1 | ) | ||||||||
Years ended 31 March 2004 and 2003
There were no exceptional items during the years ended 31 March 2004 and 2003.
Year ended 31 March 2002
| (i) | An exceptional charge of £18.5 million was incurred relating to reorganisation costs for the UK Division – Integrated Generation and Supply and primarily represented severance and related costs. |
| (ii) | An exceptional charge of £120.1 million related to the loss on disposal of and withdrawal from the group’s Appliance Retailing operations. This charge included £15.1 million of goodwill previously written off to reserves. The pre-goodwill loss of £105.0 million comprised asset impairments of £54.2 million (including a provision for impairment of tangible fixed assets of £32.2 million) and provisions for trading losses and closure costs of £50.8 million. The loss on disposal of and withdrawal from Appliance Retailing was stated before a tax credit of £21.0 million. |
| (iii) | On 23 April 2002, the group completed the sale of Aspen 4 Limited (the holding company of Southern Water plc) to First Aqua Limited for a total consideration, before expenses, of £2.05 billion including repayment and acquisition of intra-group non-trading indebtedness and assumption by First Aqua Limited of Southern Water’s non-trading debt due to third parties. An exceptional charge of £1,187.5 million related to the provision for the loss on disposal of the group’s Southern Water business. This charge included £738.2 million of goodwill previously written off to reserves and was stated before a tax credit of £2.9 million. |
| (iv) | Exceptional finance costs of £12.0 million, comprising hedging and debt redemption costs associated with the proposed refinancing of Southern Water, have been included within the results of Discontinued operations. Exceptional finance costs of £18.8 million, relating to the restructuring of the group’s debt portfolio in anticipation of the disposal of Southern Water, have been included within the results of Continuing operations. |
5 Net interest and similar charges
| 2004 | 2003 | 2002 | |||||||||
| Notes |
£m |
£m |
£m |
||||||||
| Analysis of net interest and similar charges |
|||||||||||
| Interest on bank loans and overdrafts |
13.4 | 18.6 | 32.8 | ||||||||
| Interest on other borrowings |
310.9 | 331.0 | 379.5 | ||||||||
| Finance leases |
1.9 | 2.1 | 2.3 | ||||||||
| Total interest payable |
326.2 | 351.7 | 414.6 | ||||||||
| Interest receivable |
(97.7 | ) | (107.1 | ) | (15.0 | ) | |||||
| Capitalised interest |
(i) | (10.5 | ) | (17.3 | ) | (36.1 | ) | ||||
| Net interest charge |
218.0 | 227.3 | 363.5 | ||||||||
| Unwinding of discount on provisions |
20.1 | 26.5 | 22.8 | ||||||||
| Foreign exchange loss/(gain) |
– | 0.5 | (6.9 | ) | |||||||
| Net interest and similar charges before exceptional items |
238.1 | 254.3 | 379.4 | ||||||||
| Exceptional interest on bank loans and overdrafts |
– | – | 12.0 | ||||||||
| Exceptional interest on other borrowings |
– | – | 18.8 | ||||||||
| Exceptional interest and similar charges |
4(iv) | – | – | 30.8 | |||||||
| Net interest and similar charges after exceptional items |
238.1 | 254.3 | 410.2 | ||||||||
| Interest cover (times) |
(ii) | 4.9 | 4.3 | 2.5 | |||||||
| (i) | The tax relief on the capitalised interest was £0.1 million (2003 £4.4 million, 2002 £10.5 million). |
| (ii) | Interest cover is calculated by dividing profit on ordinary activities before interest (before exceptional items and goodwill amortisation) by the sum of the net interest charge (before exceptional interest and similar charges) and the unwinding of discount on provisions. |
98 ScottishPower Annual Report and Accounts 2003/04
6 Tax on profit/(loss) on ordinary activities
| 2004 | 2003 | Before exceptional items 2002 |
Exceptional items 2002 |
2002 | |||||||||||
| £m |
£m |
£m |
£m |
£m |
|||||||||||
| Current tax: |
|||||||||||||||
| UK Corporation tax |
145.9 | 124.4 | 82.6 | (32.5 | ) | 50.1 | |||||||||
| Adjustments in respect of prior years |
25.8 | (44.9 | ) | (54.4 | ) | – | (54.4 | ) | |||||||
| Total UK Corporation tax for year |
171.7 | 79.5 | 28.2 | (32.5 | ) | (4.3 | ) | ||||||||
| Foreign tax |
36.2 | 78.9 | 17.3 | – | 17.3 | ||||||||||
| Adjustments in respect of prior years |
(33.9 | ) | – | – | – | – | |||||||||
| Total Foreign tax for year |
2.3 | 78.9 | 17.3 | – | 17.3 | ||||||||||
| Total current tax for year |
174.0 | 158.4 | 45.5 | (32.5 | ) | 13.0 | |||||||||
| Deferred tax: |
|||||||||||||||
| Origination and reversal of timing differences |
77.3 | 50.6 | 76.5 | (6.3 | ) | 70.2 | |||||||||
| Adjustments in respect of prior years |
(2.9 | ) | – | – | – | – | |||||||||
| Total deferred tax for year |
74.4 | 50.6 | 76.5 | (6.3 | ) | 70.2 | |||||||||
| Total tax on profit/(loss) on ordinary activities |
248.4 | 209.0 | 122.0 | (38.8 | ) | 83.2 | |||||||||
| Effective rate of tax before goodwill amortisation |
27.0 | % | 25.0 | % | 21.5 | % | |||||||||
The current tax charge on profit/(loss) on ordinary activities for the year varied from the standard rate of UK Corporation tax as follows:
| 2004 | 2003 | 2002 | |||||||
| £m |
£m |
£m |
|||||||
| Corporation tax at 30% |
237.6 | 209.0 | (281.6 | ) | |||||
| Losses and other permanent differences |
(12.5 | ) | 3.9 | 28.1 | |||||
| Effect of tax rate applied to overseas earnings |
(4.1 | ) | (0.7 | ) | (21.8 | ) | |||
| Permanent differences on exceptional items |
– | – | 368.2 | ||||||
| Goodwill amortisation |
38.4 | 41.7 | 44.7 | ||||||
| Adjustments in respect of prior years |
(11.0 | ) | (44.9 | ) | (54.4 | ) | |||
| Tax charge (current and deferred) |
248.4 | 209.0 | 83.2 | ||||||
| Origination and reversal of timing differences – deferred tax charge |
(74.4 | ) | (50.6 | ) | (70.2 | ) | |||
| Current tax charge for year |
174.0 | 158.4 | 13.0 | ||||||
7 Earnings/(loss) per ordinary share
(a) Earnings/(loss) per ordinary share have been calculated for all years by dividing the profit/(loss) for the financial year by the weighted average number of ordinary shares in issue during the financial year, based on the following information:
| 2004 |
2003 |
2002 |
|||||
| Basic earnings/(loss) per share |
|||||||
| Profit/(loss) for the financial year (£ million) |
537.9 | 482.6 | (987.1 | ) | |||
| Weighted average share capital (number of shares, million) |
1,829.5 | 1,843.9 | 1,837.8 | ||||
| Diluted earnings/(loss) per share |
|||||||
| Profit/(loss) for the financial year (£ million) |
545.0 | 482.6 | (987.1 | ) | |||
| Weighted average share capital (number of shares, million) |
1,890.2 | 1,848.4 | 1,840.1 | ||||
The difference between the profit/(loss) for the financial year for the purposes of the basic and the diluted earnings/(loss) per share calculations is analysed as follows:
| 2004 | 2003 | 2002 | |||||
| £m |
£m |
£m |
|||||
| Basic earnings/(loss) per share – profit/(loss) for the financial year |
537.9 | 482.6 | (987.1 | ) | |||
| Interest on convertible bonds |
7.1 | – | – | ||||
| Diluted earnings/(loss) per share – profit/(loss) for the financial year |
545.0 | 482.6 | (987.1 | ) | |||
The difference between the weighted average share capital for the purposes of the basic and the diluted earnings per share calculations is analysed as follows:
| 2004 |
2003 |
2002 | ||||
| Number of shares (million) |
||||||
| Basic earnings/(loss) per share – weighted average share capital |
1,829.5 | 1,843.9 | 1,837.8 | |||
| Outstanding share options and shares held in trust for the group’s employee share schemes |
4.9 | 4.5 | 2.3 | |||
| Convertible bonds |
55.8 | – | – | |||
| Diluted earnings/(loss) per share – weighted average share capital |
1,890.2 | 1,848.4 | 1,840.1 | |||
ScottishPower Annual Report and Accounts 2003/04 99
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
7 Earnings/(loss) per ordinary share continued
(b) The calculation of earnings/(loss) per ordinary share, on a basis which excludes exceptional items and goodwill amortisation, is based on the following adjusted earnings:
| Continuing operations and Total 2004 |
Continuing operations 2003 |
Discontinued operations 2003 |
Total 2003 |
Continuing operations 2002 |
Discontinued operations 2002 |
Total 2002 |
||||||||||
| £m |
£m |
£m |
£m |
£m |
£m |
£m |
||||||||||
| Basic earnings/(loss) per share |
||||||||||||||||
| Profit/(loss) for the financial year |
537.9 | 475.0 | 7.6 | 482.6 | 214.0 | (1,201.1 | ) | (987.1 | ) | |||||||
| Adjusting items – exceptional items (net of attributable taxation) |
– | – | – | – | 26.0 | 1,292.1 | 1,318.1 | |||||||||
| – goodwill amortisation |
128.0 | 139.0 | – | 139.0 | 146.6 | 2.4 | 149.0 | |||||||||
| Adjusted earnings |
665.9 | 614.0 | 7.6 | 621.6 | 386.6 | 93.4 | 480.0 | |||||||||
| Continuing operations and Total 2004 |
Continuing operations 2003 |
Discontinued operations 2003 |
Total 2003 |
Continuing operations 2002 |
Discontinued operations 2002 |
Total 2002 |
||||||||||
| £m |
£m |
£m |
£m |
£m |
£m |
£m |
||||||||||
| Diluted earnings/(loss) per share |
||||||||||||||||
| Profit/(loss) for the financial year |
545.0 | 475.0 | 7.6 | 482.6 | 214.0 | (1,201.1 | ) | (987.1 | ) | |||||||
| Adjusting items – exceptional items (net of attributable taxation) |
– | – | – | – | 26.0 | 1,292.1 | 1,318.1 | |||||||||
| – goodwill amortisation |
128.0 | 139.0 | – | 139.0 | 146.6 | 2.4 | 149.0 | |||||||||
| Adjusted earnings |
673.0 | 614.0 | 7.6 | 621.6 | 386.6 | 93.4 | 480.0 | |||||||||
The group’s net interest and similar charges have been allocated between continuing and discontinued operations on the basis of external and internal borrowings of the respective operations. The group’s tax charge has been allocated between continuing and discontinued operations based on the profit/(loss) before tax of the respective operations.
ScottishPower assesses the performance of the group by adjusting earnings per share, calculated in accordance with FRS 14, to exclude items it considers to be non-recurring or non-operational in nature and believes that the exclusion of such items provides a better comparison of business performance. Consequently, an adjusted earnings per share figure is presented for all years.
8 Dividends
(a) Cash dividends
| 2004 pence per ordinary |
2003 pence per ordinary |
2002 pence per ordinary |
2004 | 2003 | 2002 | |||||||
| share |
share |
share |
£m |
£m |
£m | |||||||
| First interim dividend paid |
4.75 | 7.177 | 6.835 | 87.5 | 132.5 | 125.4 | ||||||
| Second interim dividend paid |
4.75 | 7.177 | 6.835 | 87.4 | 132.7 | 125.9 | ||||||
| Third interim dividend paid |
4.75 | 7.177 | 6.835 | 87.3 | 132.1 | 126.1 | ||||||
| Final dividend |
6.25 | 7.177 | 6.835 | 112.9 | 132.2 | 126.1 | ||||||
| Total cash dividends |
20.50 | 28.708 | 27.340 | 375.1 | 529.5 | 503.5 | ||||||
| (b) Dividend in specie on demerger of Thus | ||||||||||||
| 2004 | 2003 | 2002 | ||||||||||
| Note |
£m |
£m |
£m | |||||||||
| Demerger dividend |
33 | – | – | 436.6 | ||||||||
The demerger of Thus was recorded in the group Accounts at the book value of the net assets which were deconsolidated of £421.9 million, together with £14.7 million of related goodwill which had previously been written off to reserves, giving a dividend in specie of £436.6 million.
The demerger of Thus was recorded in the individual company Accounts of Scottish Power plc at the book value of the cost of investment in the ordinary and preference shares of Thus, giving a dividend in specie of £396.3 million.
9 Reconciliation of operating profit to net cash inflow from operating activities
| 2004 | 2003 | 2002 | |||||||
| (As restated – Note 17) | |||||||||
| £m |
£m |
£m |
|||||||
| Operating profit |
1,022.6 | 945.9 | 776.6 | ||||||
| Depreciation and amortisation |
566.7 | 586.2 | 717.0 | ||||||
| (Profit)/loss on sale of tangible fixed assets |
(0.4 | ) | 2.7 | (7.7 | ) | ||||
| Amortisation of share scheme costs |
4.9 | 10.0 | 2.5 | ||||||
| Release of deferred income |
(19.5 | ) | (18.6 | ) | (17.8 | ) | |||
| Movements in provisions for liabilities and charges |
(87.6 | ) | (77.5 | ) | (93.3 | ) | |||
| (Increase)/decrease in stocks |
(51.0 | ) | (1.9 | ) | 10.4 | ||||
| (Increase)/decrease in debtors |
(38.7 | ) | (169.4 | ) | 58.4 | ||||
| (Decrease)/increase in creditors |
(33.0 | ) | 135.5 | (197.7 | ) | ||||
| Net cash inflow from operating activities |
1,364.0 | 1,412.9 | 1,248.4 | ||||||
100 ScottishPower Annual Report and Accounts 2003/04
10 Analysis of cash flows
| 2003 | 2002 | ||||||||||
| 2004 | (As restated – Note 17) |
||||||||||
| Note |
£m |
£m |
£m |
||||||||
| (a) Returns on investments and servicing of finance | |||||||||||
| Interest received |
87.6 | 112.0 | 33.1 | ||||||||
| Interest paid |
(293.0 | ) | (404.2 | ) | (402.8 | ) | |||||
| Dividends paid to minority interests |
(4.6 | ) | (4.8 | ) | (8.1 | ) | |||||
| Net cash outflow for returns on investments and servicing of finance |
(210.0 | ) | (297.0 | ) | (377.8 | ) | |||||
| (b) Capital expenditure and financial investment | |||||||||||
| Purchase of tangible fixed assets |
(892.2 | ) | (735.9 | ) | (1,244.7 | ) | |||||
| Deferred income received |
48.2 | 69.5 | 76.9 | ||||||||
| Sale of tangible fixed assets |
12.2 | 10.4 | 17.7 | ||||||||
| Sale/(purchase) of fixed asset investments |
0.6 | (19.1 | ) | 7.6 | |||||||
| Net cash outflow for capital expenditure and financial investment |
(831.2 | ) | (675.1 | ) | (1,142.5 | ) | |||||
| (c) Acquisitions and disposals | |||||||||||
| Purchase of Colorado Green joint venture |
12 | (24.6 | ) | – | – | ||||||
| Purchase of business |
12 | – | (101.3 | ) | – | ||||||
| Sale of businesses and subsidiary undertakings |
12 | (6.7 | ) | 1,900.3 | 150.0 | ||||||
| Net cash (outflow)/inflow from acquisitions and disposals | (31.3 | ) | 1,799.0 | 150.0 | |||||||
| (d) Management of liquid resources* | |||||||||||
| Cash outflow in relation to short-term deposits and other short-term investments |
(354.1 | ) | (161.1 | ) | (38.7 | ) | |||||
| Net cash outflow for management of liquid resources |
(354.1 | ) | (161.1 | ) | (38.7 | ) | |||||
| (e) Financing | |||||||||||
| Issue of ordinary share capital |
13.1 | 12.0 | 16.2 | ||||||||
| Redemption of preferred stock of PacifiCorp |
(4.6 | ) | (5.1 | ) | (69.5 | ) | |||||
| Cancellation of cross-currency swaps |
76.1 | – | – | ||||||||
| Repricing of cross-currency swaps |
403.0 | – | – | ||||||||
| Net purchase of own shares held under trust |
(28.5 | ) | (29.8 | ) | (5.8 | ) | |||||
| 459.1 | (22.9 | ) | (59.1 | ) | |||||||
| Debt due within one year: |
|||||||||||
| – net drawdown/(repayment) of uncommitted facilities |
98.7 | (203.6 | ) | 120.8 | |||||||
| – (repayment)/drawdown of committed bank loan |
– | (100.0 | ) | 100.0 | |||||||
| – net commercial paper issued/(redeemed) |
64.9 | (288.9 | ) | (52.8 | ) | ||||||
| – medium-term notes/private placements |
(29.3 | ) | (86.4 | ) | 79.9 | ||||||
| – redemption of loan notes |
(2.5 | ) | (2.2 | ) | (0.1 | ) | |||||
| – European Investment Bank loans |
– | (129.2 | ) | 114.8 | |||||||
| – mortgages |
(83.0 | ) | (5.9 | ) | 72.6 | ||||||
| – 5.875% euro-US dollar bond 2003 |
– | (183.5 | ) | 183.5 | |||||||
| – other |
(6.1 | ) | 18.3 | (1.3 | ) | ||||||
| Debt due after one year: |
|||||||||||
| – net repayment of uncommitted facilities |
– | – | (3.8 | ) | |||||||
| – medium-term notes/private placements |
2.1 | (127.3 | ) | 7.5 | |||||||
| – European Investment Bank loans |
– | – | (129.2 | ) | |||||||
| – 5.875% euro-US dollar bond 2003 |
– | – | (183.3 | ) | |||||||
| – variable coupon Australian dollar bond issue |
– | – | 233.8 | ||||||||
| – mortgages |
216.0 | (83.0 | ) | 449.5 | |||||||
| – convertible bonds |
409.9 | – | – | ||||||||
| – secured pollution control revenue bonds |
68.3 | – | 2.8 | ||||||||
| – unsecured pollution control revenue bonds |
(68.4 | ) | 2.1 | (2.9 | ) | ||||||
| – preferred securities |
(205.1 | ) | 0.3 | – | |||||||
| – other |
(1.2 | ) | (2.1 | ) | (9.7 | ) | |||||
| Finance leases: |
|||||||||||
| – finance leases |
– | – | 0.3 | ||||||||
| Increase/(decrease) in debt |
464.3 | (1,191.4 | ) | 982.4 | |||||||
| Net cash inflow/(outflow) from financing |
923.4 | (1,214.3 | ) | 923.3 | |||||||
| * | Liquid resources include term deposits of less than one year, commercial paper and other short-term investments. |
ScottishPower Annual Report and Accounts 2003/04 101
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
11 Effect of acquisitions and disposals on cash flows
| Acquisition 2003 |
Disposals 2003 |
Disposals 2002 |
|||||||
| £m |
£m |
£m |
|||||||
| Cash inflow/(outflow) from operating activities |
1.0 | 16.0 | (39.5 | ) | |||||
| Returns on investments and servicing of finance |
– | (6.6 | ) | 0.7 | |||||
| Capital expenditure and financial investment |
(1.4 | ) | (9.2 | ) | (93.2 | ) | |||
| Acquisitions and disposals |
– | – | 3.3 | ||||||
| Management of liquid resources |
– | – | 4.0 | ||||||
| Financing |
– | 4.5 | – | ||||||
| (Decrease)/increase in cash |
(0.4 | ) | 4.7 | (124.7 | ) | ||||
The analysis of cash flows of the acquisition in 2003 related to the post-acquisition cash flows of the Katy gas storage facility. The effect of the disposal on cash flows in 2003 related to the disposal of Southern Water.
The effect of disposals on cash flows in 2002 principally related to the group’s demerger of Thus and the disposal of and withdrawal from Appliance Retailing. The cash flows relating to acquisitions during 2002 were not material.
12 Analysis of cash flows in respect of acquisitions and disposals
| Acquisition 2004 |
Disposals 2004 |
Acquisition 2003 |
Disposals 2003 |
Disposals 2002 |
|||||||||||
| £m |
£m |
£m |
£m |
£m |
|||||||||||
| Cash consideration including expenses |
(24.6 | ) | – | (101.3 | ) | 1,139.4 | 13.9 | ||||||||
| Cash settlement of inter-company loan |
– | – | – | 756.4 | – | ||||||||||
| Bank overdraft disposed/(cash at bank disposed) |
– | – | – | 6.2 | (9.2 | ) | |||||||||
| Deferred consideration in respect of prior year disposals |
– | – | – | 10.5 | 152.1 | ||||||||||
| Expenses and other costs paid in respect of prior year disposals |
– | (6.7 | ) | – | (12.2 | ) | (6.8 | ) | |||||||
| (24.6 | ) | (6.7 | ) | (101.3 | ) | 1,900.3 | 150.0 | ||||||||
In 2004, the cash flows in respect of the acquisition represent PPM’s investment in the Colorado Green joint venture. The cash flows in respect of disposals principally represent expenses and other costs related to the disposal of and withdrawal from Appliance Retailing.
In 2003, the cash flows in respect of the acquisition represented the purchase of the Katy gas storage facility. The cash flows in respect of disposals principally represented the proceeds from the sale of Southern Water.
In 2002, the cash flows in respect of disposals principally represented the collection of a note receivable on the discontinued operations of PacifiCorp’s mining and resource development business, NERCO, which was sold in 1993 and the disposal of PacifiCorp’s synthetic fuel operations.
102 ScottishPower Annual Report and Accounts 2003/04
13 Analysis of net debt
| 2002/03 | At 1 April |
Cash flow | Disposal (excl. cash & overdrafts) |
Exchange | Other non-cash changes |
At 31 March |
||||||||||
| £m |
£m |
£m |
£m |
£m |
£m |
|||||||||||
| Cash at bank |
302.8 | 139.5 | – | (12.2 | ) | – | 430.1 | |||||||||
| Overdrafts |
(34.6 | ) | 11.1 | – | 2.4 | – | (21.1 | ) | ||||||||
| 150.6 | ||||||||||||||||
| Debt due after 1 year |
(5,343.0 | ) | 210.0 | 100.0 | 278.9 | (5.5 | ) | (4,759.6 | ) | |||||||
| Debt due within 1 year |
(1,192.2 | ) | 981.4 | – | 23.5 | (0.1 | ) | (187.4 | ) | |||||||
| Finance leases |
(19.4 | ) | – | – | 1.9 | – | (17.5 | ) | ||||||||
| 1,191.4 | ||||||||||||||||
| Other deposits |
78.0 | 161.1 | – | (4.6 | ) | – | 234.5 | |||||||||
| Total |
(6,208.4 | ) | 1,503.1 | 100.0 | 289.9 | (5.6 | ) | (4,321.0 | ) | |||||||
‘Other non-cash changes’ to net debt represents amortisation of finance costs of £1.6 million and finance costs of £4.0 million representing the effects of the Retail Price Index (“RPI”) on bonds carrying an RPI coupon.
| 2003/04 | At 1 April |
Cash flow | Exchange | Other non-cash changes |
At 31 March |
||||||||||
| £m |
£m |
£m |
£m |
£m |
|||||||||||
| Cash at bank |
430.1 | 346.6 | (17.8 | ) | – | 758.9 | |||||||||
| Overdrafts |
(21.1 | ) | (1.5 | ) | 2.5 | – | (20.1 | ) | |||||||
| 345.1 | |||||||||||||||
| Debt due after 1 year |
(4,759.6 | ) | (421.6 | ) | 364.0 | 171.1 | (4,646.1 | ) | |||||||
| Debt due within 1 year |
(187.4 | ) | (42.7 | ) | 37.3 | (197.8 | ) | (390.6 | ) | ||||||
| Finance leases |
(17.5 | ) | – | 2.5 | – | (15.0 | ) | ||||||||
| (464.3 | ) | ||||||||||||||
| Other deposits |
234.5 | 354.1 | (0.2 | ) | – | 588.4 | |||||||||
| Total |
(4,321.0 | ) | 234.9 | 388.3 | (26.7 | ) | (3,724.5 | ) | |||||||
‘Other non-cash changes’ to net debt represents the movement in debt of £197.8 million due after one year to due within one year, the share of debt in joint arrangements of £6.4 million, amortisation of finance costs of £6.1 million and finance costs of £14.2 million representing the effects of the RPI on bonds carrying an RPI coupon.
ScottishPower Annual Report and Accounts 2003/04 103
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
14 Segmental balance sheet information
| 2004 | 2003 (As restated – Note 17) |
||||||||
| Note |
£m |
£m |
|||||||
| (a) Net assets by segment |
|||||||||
| United Kingdom – continuing operations |
|||||||||
| UK Division – Integrated Generation and Supply |
1,022.5 | 908.4 | |||||||
| Infrastructure Division – Power Systems |
2,337.4 | 2,175.4 | |||||||
| United Kingdom total – continuing operations |
3,359.9 | 3,083.8 | |||||||
| United States – continuing operations |
|||||||||
| PacifiCorp |
5,935.8 | 6,787.2 | |||||||
| PPM |
439.0 | 375.8 | |||||||
| United States total – continuing operations |
6,374.8 | 7,163.0 | |||||||
| Total continuing operations |
9,734.7 | 10,246.8 | |||||||
| Unallocated net liabilities |
|||||||||
| Net debt |
(3,724.5 | ) | (4,321.0 | ) | |||||
| Deferred tax |
(1,242.2 | ) | (1,301.9 | ) | |||||
| Corporate tax |
(237.7 | ) | (251.1 | ) | |||||
| Proposed dividend |
(112.9 | ) | (132.2 | ) | |||||
| Fixed asset investments |
194.8 | 193.3 | |||||||
| Other |
(i | ) | 139.6 | 194.9 | |||||
| Total unallocated net liabilities |
(4,982.9 | ) | (5,618.0 | ) | |||||
| Total |
4,751.8 | 4,628.8 | |||||||
Net asset value per ordinary share has been calculated based on net assets (after adjusting for minority interests) and the number of shares in issue (after adjusting for the effect of shares held in trust) at the end of the respective financial years:
| 2004 |
2003 (As restated – Note 17) | ||||||
| Net assets (as adjusted) (£ million) |
4,690.9 | 4,554.9 | |||||
| Number of ordinary shares in issue at year end (as adjusted) (number of shares, million) |
1,830.6 | 1,833.5 | |||||
| (b) Capital expenditure by segment
|
|||||||
| 2004 | 2003 | ||||||
| Note |
£m |
£m | |||||
| United Kingdom – continuing operations |
|||||||
| UK Division – Integrated Generation and Supply |
(ii | ) | 93.4 | 73.2 | |||
| Infrastructure Division – Power Systems |
(ii | ) | 287.2 | 273.1 | |||
| United Kingdom total – continuing operations |
380.6 | 346.3 | |||||
| United States – continuing operations |
|||||||
| PacifiCorp |
(ii | ) | 464.6 | 388.4 | |||
| PPM |
103.8 | 36.1 | |||||
| United States total – continuing operations |
568.4 | 424.5 | |||||
| Total continuing operations |
949.0 | 770.8 | |||||
| United Kingdom – discontinued operations |
|||||||
| Southern Water |
(ii | ) | – | 15.8 | |||
| Total discontinued operations |
– | 15.8 | |||||
| Total |
949.0 | 786.6 | |||||
| (c) Total assets by segment
|
|||||||
| 2004 | 2003 (As restated – Note 17) | ||||||
| Note |
£m |
£m | |||||
| United Kingdom – continuing operations |
|||||||
| UK Division – Integrated Generation and Supply |
1,742.6 | 1,601.4 | |||||
| Infrastructure Division – Power Systems |
2,976.0 | 2,808.7 | |||||
| United Kingdom total – continuing operations |
4,718.6 | 4,410.1 | |||||
| United States – continuing operations |
|||||||
| PacifiCorp |
6,718.7 | 7,709.2 | |||||
| PPM |
556.2 | 542.8 | |||||
| United States total – continuing operations |
7,274.9 | 8,252.0 | |||||
| Total continuing operations |
11,993.5 | 12,662.1 | |||||
| Unallocated total assets |
(iii | ) | 1,813.3 | 1,196.0 | |||
| Total |
13,806.8 | 13,858.1 | |||||
104 ScottishPower Annual Report and Accounts 2003/04
14 Segmental balance sheet information continued
| (i) | Other unallocated net liabilities principally includes interest and amounts relating to gains arising on retranslation of forward contracts and cross-currency swaps used to hedge overseas net investments. |
| (ii) | Capital expenditure by business segment is stated gross of capital grants and customer contributions. Capital expenditure net of contributions amounted to £900.8 million (2003 £717.1 million). Capital grants and customer contributions receivable during the year of £48.2 million (2003 £69.5 million) comprised UK Division – Integrated Generation and Supply £0.1 million (2003 £5.4 million), Infrastructure Division – Power Systems £27.6 million (2003 £43.2 million), PacifiCorp £20.5 million (2003 £20.0 million) and Southern Water £nil (2003 £0.9 million). |
| (iii) | Unallocated total assets includes investments, interest receivable, bank deposits and amounts relating to gains arising on retranslation of forward contracts and cross-currency swaps used to hedge overseas net investments. |
15 Intangible fixed assets
| Year ended 31 March 2003 | Goodwill | |||||
| Note |
£m |
|||||
| Cost: |
||||||
| At 1 April 2002 |
2,977.8 | |||||
| Acquisition |
(i | ) | 12.4 | |||
| Exchange |
(286.0 | ) | ||||
| At 31 March 2003 |
2,704.2 | |||||
| Amortisation: |
||||||
| At 1 April 2002 |
318.9 | |||||
| Amortisation for the year |
139.0 | |||||
| Exchange |
(34.3 | ) | ||||
| At 31 March 2003 |
423.6 | |||||
| Net book value: |
||||||
| At 31 March 2003 |
2,280.6 | |||||
| At 31 March 2002 |
2,658.9 | |||||
| Year ended 31 March 2004 | Goodwill | |||||
| £m |
||||||
| Cost: |
||||||
| At 1 April 2003 |
2,704.2 | |||||
| Exchange |
(364.5 | ) | ||||
| At 31 March 2004 |
2,339.7 | |||||
| Amortisation: |
||||||
| At 1 April 2003 |
423.6 | |||||
| Amortisation for the year |
128.0 | |||||
| Exchange |
(67.8 | ) | ||||
| At 31 March 2004 |
483.8 | |||||
| Net book value: |
||||||
| At 31 March 2004 |
1,855.9 | |||||
| At 31 March 2003 |
2,280.6 | |||||
Goodwill capitalised is being amortised over its estimated useful economic life of 20 years.
| (i) | The provisional fair values attributed to the acquisition of the Katy gas storage facility in 2002/03, that resulted in goodwill of £12.4 million, have not required amendment in the post-acquisition period to March 2004. |
ScottishPower Annual Report and Accounts 2003/04 105
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
16 Tangible fixed assets
| Land and buildings |
Water infrastructure assets |
Plant and machinery |
Vehicles and equipment |
Total | ||||||||||||||
| Notes |
£m |
£m |
£m |
£m |
£m |
|||||||||||||
| Year ended 31 March 2003 |
||||||||||||||||||
| Cost or valuation: |
||||||||||||||||||
| At 1 April 2002 |
1,440.9 | 826.4 | 10,169.4 | 1,402.7 | 13,839.4 | |||||||||||||
| Additions |
24.1 | 0.1 | 651.8 | 110.6 | 786.6 | |||||||||||||
| Acquisition |
7.1 | – | 81.2 | – | 88.3 | |||||||||||||
| Grants and contributions |
– | (0.8 | ) | – | – | (0.8 | ) | |||||||||||
| Disposals |
(7.3 | ) | (0.3 | ) | (45.8 | ) | (52.9 | ) | (106.3 | ) | ||||||||
| Valuation adjustment |
(i | ) | – | – | 149.8 | – | 149.8 | |||||||||||
| Disposal of Southern Water |
32 | (811.1 | ) | (825.4 | ) | (714.3 | ) | (235.1 | ) | (2,585.9 | ) | |||||||
| Exchange |
(21.0 | ) | – | (541.3 | ) | (58.8 | ) | (621.1 | ) | |||||||||
| At 31 March 2003 |
632.7 | – | 9,750.8 | 1,166.5 | 11,550.0 | |||||||||||||
| Depreciation: |
||||||||||||||||||
| At 1 April 2002 |
241.0 | – | 1,464.3 | 481.8 | 2,187.1 | |||||||||||||
| Reclassification |
– | – | 3.2 | (3.2 | ) | – | ||||||||||||
| Charge for the year |
13.9 | 1.5 | 287.9 | 143.9 | 447.2 | |||||||||||||
| Disposals |
(0.8 | ) | (0.3 | ) | (40.8 | ) | (51.1 | ) | (93.0 | ) | ||||||||
| Valuation adjustment |
(i | ) | – | – | 149.8 | – | 149.8 | |||||||||||
| Disposal of Southern Water |
32 | (75.0 | ) | (1.2 | ) | (2.0 | ) | (33.0 | ) | (111.2 | ) | |||||||
| Exchange |
(1.8 | ) | – | (43.0 | ) | (13.8 | ) | (58.6 | ) | |||||||||
| At 31 March 2003 |
177.3 | – | 1,819.4 | 524.6 | 2,521.3 | |||||||||||||
| Net book value: |
||||||||||||||||||
| At 31 March 2003 |
455.4 | – | 7,931.4 | 641.9 | 9,028.7 | |||||||||||||
| At 31 March 2002 |
1,199.9 | 826.4 | 8,705.1 | 920.9 | 11,652.3 | |||||||||||||
| Year ended 31 March 2004 |
||||||||||||||||||
| Cost or valuation: |
||||||||||||||||||
| At 1 April 2003 |
632.7 | – | 9,750.8 | 1,166.5 | 11,550.0 | |||||||||||||
| Reclassification |
(21.3 | ) | – | 2.8 | 18.5 | – | ||||||||||||
| Additions |
(ii | ) | 16.0 | – | 677.2 | 255.8 | 949.0 | |||||||||||
| Disposals |
(7.2 | ) | – | (15.6 | ) | (30.1 | ) | (52.9 | ) | |||||||||
| Exchange |
(24.8 | ) | – | (772.5 | ) | (89.7 | ) | (887.0 | ) | |||||||||
| At 31 March 2004 |
595.4 | – | 9,642.7 | 1,321.0 | 11,559.1 | |||||||||||||
| Depreciation: |
||||||||||||||||||
| At 1 April 2003 |
177.3 | – | 1,819.4 | 524.6 | 2,521.3 | |||||||||||||
| Reclassification |
(14.7 | ) | – | (1.0 | ) | 15.7 | – | |||||||||||
| Charge for the year |
20.1 | – | 245.6 | 173.0 | 438.7 | |||||||||||||
| Disposals |
(1.0 | ) | – | (15.6 | ) | (24.5 | ) | (41.1 | ) | |||||||||
| Exchange |
– | – | (82.1 | ) | (34.3 | ) | (116.4 | ) | ||||||||||
| At 31 March 2004 |
181.7 | – | 1,966.3 | 654.5 | 2,802.5 | |||||||||||||
| Net book value: |
||||||||||||||||||
| At 31 March 2004 |
413.7 | – | 7,676.4 | 666.5 | 8,756.6 | |||||||||||||
| At 31 March 2003 |
455.4 | – | 7,931.4 | 641.9 | 9,028.7 | |||||||||||||
Historical cost analysis
| 2004 | 2003 | |||||
| £m |
£m |
|||||
| Cost |
11,505.1 | 11,496.0 | ||||
| Depreciation based on cost |
(2,790.1 | ) | (2,510.8 | ) | ||
| Net book value based on cost |
8,715.0 | 8,985.2 | ||||
Included in the cost or valuation of tangible fixed assets above are:
| 2004 | 2003 | ||||||
| Notes |
£m |
£m | |||||
| Assets in the course of construction |
637.8 | 556.1 | |||||
| Other assets not subject to depreciation |
(iv | ) | 118.4 | 114.3 | |||
| Capitalised interest |
(v | ) | 46.2 | 40.4 | |||
| (i) | The valuation adjustment in 2002/03 represented an adjustment to the cost and accumulated depreciation of the tangible fixed assets of Southern Water on disposal. |
| (ii) | The additions in the year of £949.0 million include £24.9 million relating to an increase in the provision for mine reclamation costs. |
| (iii) | The Manweb distribution and Southern Water operational assets were revalued by the directors on 30 September 1997 on a market value basis. The valuation of the Manweb distribution assets has not been and will not be updated, as permitted under the transitional provisions of FRS 15 ‘Tangible fixed assets’. The net book value of tangible fixed assets included at valuation at 31 March 2004 relates to Manweb distribution assets and was £563.9 million (2003 £580.8 million). |
| (iv) | Other assets not subject to depreciation are land. Land and buildings held by the group are predominantly freehold. |
| (v) | Interest on the funding attributable to major capital projects was capitalised during the year at a rate of 6% (2003 7%) in the US. There was no such interest capitalised in the UK during the year (2003 interest capitalised at 5%). |
| (vi) | The historical cost of fully depreciated tangible fixed assets still in use was £375.6 million (2003 £298.0 million). |
| (vii) | Capitalised computer software costs developed for internal use include employee, interest and other external direct costs of materials and services which are directly attributable to the development of computer software. Cumulative computer software costs capitalised are £560.8 million (2003 £525.8 million, 2002 £490.7 million). The depreciation charge was £61.2 million (2003 £79.6 million, 2002 £73.4 million). |
| (viii) | The net book value of land and buildings under finance leases at 31 March 2004 was £15.0 million (2003 £17.5 million). The charge for depreciation against these assets during the year was £0.7 million (2003 £0.1 million). |
106 ScottishPower Annual Report and Accounts 2003/04
17 Fixed asset investments
|
Joint ventures |
Associated £m |
Own £m |
Other £m |
Total £m |
||||||||||||||||
| Note |
Shares £m |
Loans £m |
||||||||||||||||||
| Cost or valuation: |
||||||||||||||||||||
| At 1 April 2002 – as originally stated |
0.1 | 36.8 | 5.2 | 71.2 | 152.3 | 265.6 | ||||||||||||||
| Prior year adjustment for UITF 38 |
– | – | – | (71.2 | ) | – | (71.2 | ) | ||||||||||||
| At 1 April 2002 – as restated |
0.1 | 36.8 | 5.2 | – | 152.3 | 194.4 | ||||||||||||||
| Additions |
– | 6.8 | – | – | 19.4 | 26.2 | ||||||||||||||
| Share of retained (loss)/profit |
– | (0.3 | ) | 0.3 | – | – | – | |||||||||||||
| Disposals and other |
– | (3.1 | ) | (0.8 | ) | – | (5.3 | ) | (9.2 | ) | ||||||||||
| Disposal of Southern Water |
32 | – | – | (1.9 | ) | – | – | (1.9 | ) | |||||||||||
| Exchange |
– | – | – | – | (16.2 | ) | (16.2 | ) | ||||||||||||
| At 31 March 2003 – as originally stated |
0.1 | 40.2 | 2.8 | 97.1 | 150.2 | 290.4 | ||||||||||||||
| Prior year adjustment for UITF 38 |
– | – | – | (97.1 | ) | – | (97.1 | ) | ||||||||||||
| At 31 March 2003 – as restated |
0.1 | 40.2 | 2.8 | – | 150.2 | 193.3 | ||||||||||||||
| Additions |
24.6 | 1.1 | – | – | 2.2 | 27.9 | ||||||||||||||
| Share of retained profit |
0.5 | – | 0.2 | – | – | 0.7 | ||||||||||||||
| Disposals and other |
– | (2.5 | ) | (0.3 | ) | – | (1.6 | ) | (4.4 | ) | ||||||||||
| Exchange |
(1.7 | ) | – | – | – | (21.0 | ) | (22.7 | ) | |||||||||||
| At 31 March 2004 |
23.5 | 38.8 | 2.7 | – | 129.8 | 194.8 | ||||||||||||||
The group has 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 have also been made to Other creditors and Other provisions. Comparative figures have been restated in the Balance Sheet, Cash Flow Statement and related Notes. The implementation of UITF 38 had no impact on the group’s previously reported profits and losses.
The effect of UITF 38 on the group’s previously reported net assets is as follows:
| As at 31 March 2003 | ||||||||||||
| Fixed asset investments |
Other creditors |
Other provisions |
Net assets |
|||||||||
| £m |
£m |
£m |
£m |
|||||||||
| As previously reported |
290.4 | 1,785.7 | 610.9 | 4,712.2 | ||||||||
| Effect of implementing new accounting policy |
(97.1 | ) | (8.4 | ) | (5.3 | ) | (83.4 | ) | ||||
| As restated |
193.3 | 1,777.3 | 605.6 | 4,628.8 | ||||||||
The principal subsidiary undertakings, joint ventures and associated undertakings are listed on page 146.
Details of listed investments, included above, are given below:
| £m | ||
| Balance Sheet value at 31 March 2004 |
57.2 | |
| Market value at 31 March 2004 |
55.2 | |
ScottishPower Annual Report and Accounts 2003/04 107
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
18 Stocks
| 2004 | 2003 | |||
| £m |
£m | |||
| Raw materials and consumables |
91.7 | 91.7 | ||
| Fuel stocks |
88.2 | 50.3 | ||
| Work in progress |
5.6 | 12.6 | ||
| 185.5 | 154.6 | |||
19 Debtors
| Notes |
2004 | 2003 | ||||||
| £m |
£m |
|||||||
| (a) Amounts falling due within one year: |
||||||||
| Trade debtors |
(i) | 407.5 | 424.8 | |||||
| Amounts receivable under finance leases – US |
(ii), (iii) | 28.3 | 29.4 | |||||
| Less non-recourse financing |
(16.1 | ) | (20.9 | ) | ||||
| 12.2 | 8.5 | |||||||
| Amounts receivable under finance leases – UK |
(iii) | 0.1 | 0.1 | |||||
| Prepayments and accrued income |
538.2 | 393.3 | ||||||
| Other debtors |
(iv) | 390.9 | 530.1 | |||||
| 1,348.9 | 1,356.8 | |||||||
| (b) Amounts falling due after more than one year: |
||||||||
| Amounts receivable under finance leases – US |
(ii), (iii) | 171.9 | 233.0 | |||||
| Less non-recourse financing |
(93.4 | ) | (127.3 | ) | ||||
| 78.5 | 105.7 | |||||||
| Amounts receivable under finance leases – UK |
(iii) | 4.0 | 4.1 | |||||
| Other debtors |
35.3 | 69.7 | ||||||
| 1,466.7 | 1,536.3 | |||||||
| (i) | Trade debtors are stated net of provisions for doubtful debts of £57.9 million (2003 £76.7 million). |
| (ii) | The group’s finance lease assets in the US which are financed by non-recourse borrowing qualify for linked presentation under FRS 5. The provider of the finance has agreed in writing in the finance documentation that it will seek repayment of the finance, as to both principal and interest, only to the extent that sufficient funds are generated by the specific assets it has financed and that it will not seek recourse in any other form. The directors confirm that the group has no obligation to support any losses arising under these leases nor is there any intention to do so. |
| (iii) | Amounts receivable under finance leases falling due after more than one year at 31 March 2004 of £175.9 million (2003 £237.1 million) are due as follows: within 1-2 years, £21.4 million (2003 £32.3 million); within 2-3 years, £28.6 million (2003 £25.8 million); within 3-4 years, £23.9 million (2003 £33.2 million); within 4-5 years, £18.1 million (2003 £27.7 million) and after 5 years, £83.9 million (2003 £118.1 million). Amounts received under finance leases during the year were £43.2 million (2003 £51.6 million). |
| (iv) | Included within other debtors falling due within one year is an amount of £201.1 million (2003 £297.1 million) relating to the value of net investment cross-currency swaps and £59.3 million (2003 £9.5 million) relating to net investment forward contracts as disclosed in Note 20(b). |
108 ScottishPower Annual Report and Accounts 2003/04
20 Loans and other borrowings
Details of the group’s objectives, policies and strategy with regard to financial instruments and risk management are contained within the Financial Review on pages 33 to 61. The analyses of financial instruments in this Note, other than currency disclosures, do not include short-term debtors and creditors as permitted by FRS 13.
| Weighted average interest rate 2004 |
Weighted average interest rate 2003 |
2004 |
2003 | ||||||||||
| Notes |
£m |
£m | |||||||||||
| (a) Analysis by instrument | |||||||||||||
| Unsecured debt of UK businesses |
|||||||||||||
| Bank overdraft |
– | – | 0.1 | 2.7 | |||||||||
| Committed bank loans |
– | 4.2 | % | – | – | ||||||||
| Uncommitted bank loans |
3.8 | % | 4.4 | % | 108.0 | 9.3 | |||||||
| Medium-term notes/private placements |
(i | ) | 5.4 | % | 5.0 | % | 1,023.4 | 1,035.7 | |||||
| Loan notes |
(ii | ) | 3.7 | % | 4.1 | % | 1.2 | 3.6 | |||||
| European Investment Bank loans |
(iii | ) | 5.9 | % | 5.9 | % | 199.2 | 199.2 | |||||
| Variable rate Australian dollar bond 2011 |
4.4 | % | 4.7 | % | 234.7 | 234.2 | |||||||
| 4.000% US dollar convertible bonds |
(iv | ) | 4.4 | % | – | 374.7 | – | ||||||
| 5.250% deutschmark bond 2008 |
6.8 | % | 6.8 | % | 246.0 | 245.8 | |||||||
| 6.625% euro-sterling bond 2010 |
6.7 | % | 6.7 | % | 198.6 | 198.4 | |||||||
| 8.375% euro-sterling bond 2017 |
8.5 | % | 8.5 | % | 197.8 | 197.7 | |||||||
| 6.750% euro-sterling bond 2023 |
6.8 | % | 6.8 | % | 247.3 | 247.2 | |||||||
| Unsecured debt of US businesses |
|||||||||||||
| Bank overdraft |
– | – | 20.0 | 18.4 | |||||||||
| Commercial paper |
(v | ) | 1.1 | % | 1.4 | % | 68.0 | 15.8 | |||||
| Preferred securities |
(vi | ) | – | 8.6 | % | – | 208.9 | ||||||
| Pollution control revenue bonds |
(vii | ) | 1.8 | % | 2.0 | % | 183.7 | 284.9 | |||||
| Finance leases |
(viii | ) | 11.9 | % | 11.9 | % | 15.0 | 17.5 | |||||
| Other borrowings |
1.1 | % | 1.0 | % | 11.3 | 18.1 | |||||||
| Unsecured debt |
3,129.0 | 2,937.4 | |||||||||||
| Secured debt of US businesses |
|||||||||||||
| First mortgage and collateral bonds |
(ix | ) | 7.2 | % | 7.5 | % | 1,601.8 | 1,726.0 | |||||
| Pollution control revenue bonds |
(vii | ) | 2.6 | % | 2.4 | % | 215.6 | 179.2 | |||||
| Other secured borrowings |
(x | ) | 6.9 | % | 6.5 | % | 125.4 | 143.0 | |||||
| Secured debt |
1,942.8 | 2,048.2 | |||||||||||
| 5,071.8 | 4,985.6 | ||||||||||||
| Loans and other borrowings are repayable as follows: |
|||||||||||||
| Within one year, or on demand |
410.7 | 208.5 | |||||||||||
| After more than one year |
4,661.1 | 4,777.1 | |||||||||||
| 5,071.8 | 4,985.6 | ||||||||||||
| (i) | Medium-term notes/private placements |
Scottish Power plc and Scottish Power UK plc have an established joint US$7.0 billion (2003 US$7.0 billion) euro-medium-term note programme. Scottish Power plc has not yet issued under the programme. Paper is issued in a range of currencies and swapped back into sterling. As at 31 March 2004, maturities range from 1 to 36 years.
| (ii) | Loan notes |
All loan notes are redeemable at the holders’ discretion. The ultimate maturity date for currently outstanding loan notes is 2006.
| (iii) | European Investment Bank (“EIB”) loans |
These loans incorporate agreements with various interest rates and maturity dates. The maturity dates of these arrangements range from 2009 to 2011.
| (iv) | Convertible bonds |
Scottish Power Finance (Jersey) Limited (“the Issuer”) has issued US$700 million 4.00% step-up perpetual subordinated convertible bonds guaranteed by Scottish Power plc. The bonds are convertible into redeemable preference shares of the Issuer which will be exchangeable immediately on issuance for ordinary shares in Scottish Power plc. The Exchange Price was initially set at £4.60 but will be subject to change on the occurence of certain events set out in the Offering Circular, including payment of dividends greater than amounts set out in the bond agreement, capital restructuring and change of control. The exchange rate to be used to convert US dollar denominated preference shares into sterling is 1.6776. Conversion of the bonds into shares is at the option of the bondholders. During the period up to 3 July 2011, they can opt to convert the bonds into preference shares of the Issuer which are immediately exchangeable into ordinary shares of Scottish Power plc. If the bonds remain outstanding after 10 July 2011, they will bear interest at a rate of 4.00% per annum above the London Inter Bank Offer Rate for three month US dollar deposits. The bonds are perpetual, so there is no fixed redemption date. There are, however, occasions where redemption may occur. The Issuer may redeem the bonds: i) if, after 10 July 2009, for the preceeding 30 dealing days the average of the middle market quotations of an ordinary share has been at least 130% of the average Exchange Price; ii) if, at any time, conversion rights have been exercised and/or purchases effected in respect of 85% or more in principal amount of the bonds; or iii) at any time after 10 July 2011, provided all of the outstanding bonds are redeemed. Under ii) and iii), the redemption amount will be principal value plus accrued, unpaid interest. Under i), the redemption will be by way of the issue of shares. The bondholders may require redemption if an offer is made to the shareholders of Scottish Power plc to buy their shares in the company. The redemption amount will be principal value plus accrued, unpaid interest.
| (v) | Commercial paper |
Scottish Power UK plc has an established US$2.0 billion (2003 US$2.0 billion) euro-commercial paper programme. Paper was issued in a range of currencies and swapped back into sterling. No issues have been made under the programme since April 2002. PacifiCorp has a US$1.5 billion (2003 US$1.5 billion) domestic commercial paper programme. Amounts borrowed under the commercial paper programmes are repayable in less than one year.
ScottishPower Annual Report and Accounts 2003/04 109
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
20 Loans and other borrowings continued
| (vi) | Preferred securities |
Wholly-owned subsidiary trusts of PacifiCorp (“the Trusts”) issued redeemable preferred securities representing preferred undivided beneficial interests in the assets of the Trusts. The sole assets of the Trusts were junior subordinated deferrable interest debentures of PacifiCorp that bore interest at the same rates as the preferred securities to which they relate, and certain rights under related guarantees by PacifiCorp. During August 2003, PacifiCorp redeemed, prior to maturity, all of the outstanding preferred securities and the Trusts were subsequently cancelled.
| (vii) | Pollution control revenue bonds |
These are bonds issued by qualified tax exempt entities to finance, or refinance, the cost of certain pollution control, solid waste disposal and sewage facilities. PacifiCorp has entered into agreements with the issuers pursuant to which PacifiCorp received the proceeds of the issuance and agreed to make payments sufficient to pay principal of, interest on, and certain additional expenses. The interest on the bonds is not subject to federal income taxation for most bondholders. In some cases, PacifiCorp has issued first mortgage and collateral bonds as collateral for repayment.
| (viii) | Finance leases |
These are facility leases that are accounted for as capital leases, maturity dates range from 2014 to 2022.
| (ix) | First mortgage and collateral bonds |
First mortgage and collateral bonds of PacifiCorp may be issued in amounts limited by its Electric operation’s property, earnings and other provisions of the mortgage indenture. Approximately US$12.4 billion of the eligible assets (based on original costs) of PacifiCorp is subject to the lien of the mortgage.
| (x) | Other secured borrowings |
Included within other secured borrowings is ScottishPower’s share of debt in a joint arrangement for the Klamath co-generation plant. The borrowings are the subject of a guarantee, for US$60.0 million, provided by PacifiCorp Holdings Inc. in respect of second lien revenue bonds.
| At 31 March 2004 | At 31 March 2003 | |||||||||||
| Book amount |
Fair value |
Book amount |
Fair value |
|||||||||
| £m |
£m |
£m |
£m |
|||||||||
| (b) Fair value of financial instruments | ||||||||||||
| Short-term debt and current portion of long-term debt |
411.1 | 411.1 | 209.2 | 209.2 | ||||||||
| Long-term debt |
4,686.2 | 5,166.9 | 4,807.2 | 5,384.3 | ||||||||
| Cross-currency swaps |
(25.5 | ) | (43.2 | ) | (30.8 | ) | (50.0 | ) | ||||
| Total debt |
5,071.8 | 5,534.8 | 4,985.6 | 5,543.5 | ||||||||
| Interest rate swaps |
(6.4 | ) | 16.1 | — | (22.6 | ) | ||||||
| Interest rate swaptions |
2.6 | 2.4 | 4.0 | 2.6 | ||||||||
| Forward rate agreements |
— | — | — | 8.4 | ||||||||
| Forward contracts |
(1.9 | ) | (70.0 | ) | — | (46.7 | ) | |||||
| Net investment forward contracts |
(59.3 | ) | (47.4 | ) | (9.5 | ) | (9.9 | ) | ||||
| Net investment cross-currency swaps |
(201.1 | ) | (177.6 | ) | (297.1 | ) | (255.8 | ) | ||||
| Energy hedge contracts |
— | 5.1 | — | 35.0 | ||||||||
| Energy trading contracts |
(0.6 | ) | (0.6 | ) | (0.4 | ) | (0.4 | ) | ||||
| Total financial instruments |
4,805.1 | 5,262.8 | 4,682.6 | 5,254.1 | ||||||||
The assumptions used to estimate fair values of financial instruments are summarised below:
| (i) | For short-term borrowings (uncommitted borrowing, commercial paper and short-term borrowings under the committed facilities), the book value approximates to fair value because of their short maturities. |
| (ii) | The fair values of all quoted euro bonds are based on their closing clean market price converted at the spot rate of exchange as appropriate. |
| (iii) | The fair values of the EIB loans have been calculated by discounting their future cash flows at market rates adjusted to reflect the redemption adjustments allowed under each agreement. |
| (iv) | The fair values of unquoted debt have been calculated by discounting the estimated cash flows for each instrument at the appropriate market discount rate in the currency of issue in effect at the balance sheet date. |
| (v) | The fair values of the sterling interest rate swaps and sterling forward rate agreements have been estimated by calculating the present value of estimated cash flows. |
| (vi) | The fair values of the sterling interest rate swaptions are estimated using the sterling yield curve and implied volatilities as at 31 March. |
| (vii) | The fair values of the cross-currency swaps have been estimated by adding the present values of the two sides of each swap. The present value of each side of the swap is calculated by discounting the estimated future cash flows for that side, using the appropriate market discount rates for that currency in effect at the balance sheet date. |
| (viii) | The fair values of the forward contracts are estimated using market forward exchange rates on 31 March. |
| (ix) | The fair values of gas futures are the margin calls under those contracts. |
| (x) | The fair values of weather derivatives have been estimated assuming for water related derivatives a normal water year in several water basins, and for temperature related derivatives a normal daily high temperature of certain cities in the US. |
110 ScottishPower Annual Report and Accounts 2003/04
20 Loans and other borrowings continued
| 2004 | 2003 | |||
| £m |
£m | |||
| (c) Maturity analysis of financial liabilities | ||||
| Repayments fall due as follows: |
||||
| Within one year, or on demand |
410.7 | 208.5 | ||
| Between one and two years |
278.2 | 223.0 | ||
| Between two and three years |
227.6 | 302.2 | ||
| Between three and four years |
91.5 | 246.2 | ||
| Between four and five years |
616.6 | 101.6 | ||
| More than five years |
3,447.2 | 3,904.1 | ||
| 5,071.8 | 4,985.6 | |||
Included in the within one year, or on demand figure above is £nil, in the between two and five years figures is £1.0 million and in the more than five years figure is £14.0 million relating to finance leases (2003 £0.1 million, £0.8 million and £16.6 million respectively).
| 2005 | 2006 | 2007 | 2008 | 2009 | Thereafter | Total | Fair Value* | |||||||||||||||||
| £m |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
|||||||||||||||||
| Liabilities: |
||||||||||||||||||||||||
| Fixed rate (GBP) |
50.0 | — | 100.0 | 25.0 | 55.0 | 1,083.9 | 1,313.9 | 1,427.8 | ||||||||||||||||
| Average interest rate (GBP) |
6.6 | % | — | 6.5 | % | 6.7 | % | 5.5 | % | 6.7 | % | 6.6 | % | |||||||||||
| Fixed rate (USD) – UK group |
— | — | — | — | — | 427.0 | 427.0 | 469.4 | ||||||||||||||||
| Average interest rate (USD) – UK group |
— | — | — | — | — | 4.1 | % | 4.1 | % | |||||||||||||||
| Fixed rate (USD) – US group |
132.7 | 147.3 | 115.4 | 66.5 | 221.8 | 1,122.9 | 1,806.6 | 2,078.0 | ||||||||||||||||
| Average interest rate (USD) – US group |
7.3 | % | 7.4 | % | 7.6 | % | 7.7 | % | 6.1 | % | 7.1 | % | 7.1 | % | ||||||||||
| Fixed rate (CZK) |
— | 40.7 | — | — | — | — | 40.7 | 43.1 | ||||||||||||||||
| Average interest rate (CZK) |
— | 6.9 | % | — | — | — | — | 6.9 | % | |||||||||||||||
| Fixed rate (EUR) |
15.0 | — | — | — | 285.2 | — | 300.2 | 320.1 | ||||||||||||||||
| Average interest rate (EUR) |
4.8 | % | — | — | — | 5.2 | % | — | 5.2 | % | ||||||||||||||
| Index-linked (GBP) |
— | — | — | — | — | 195.4 | 195.4 | 213.3 | ||||||||||||||||
| Average interest rate (GBP) |
— | — | — | — | — | 3.49 x RPI | 3.49 x RPI | |||||||||||||||||
| Variable rate (GBP) |
114.3 | — | — | — | 30.0 | 57.0 | 201.3 | 201.3 | ||||||||||||||||
| Average interest rate (GBP) |
1m LIBOR | — | — | — | 6m LIBOR | 3m LIBOR | 2m LIBOR | |||||||||||||||||
| Variable rate (USD) – UK group |
— | 54.4 | — | — | 19.0 | — | 73.4 | 73.6 | ||||||||||||||||
| Average interest rate (USD) – UK group |
— | 3m LIBOR | — | — | 3m LIBOR | — | 3m LIBOR | |||||||||||||||||
| Variable rate (USD) – US group |
99.1 | 8.5 | 12.2 | — | — | 273.9 | 393.7 | 393.9 | ||||||||||||||||
| Average interest rate (USD) – US group |
1m LIBOR | BMA | BMA | — | — | BMA | BMA | |||||||||||||||||
| Variable rate (USD) – US group |
— | — | — | — | — | 40.5 | 40.5 | 40.5 | ||||||||||||||||
| Average interest rate (USD) – US group |
— | — | — | — | — | MCBY | MCBY | |||||||||||||||||
| Variable rate (AUD) |
— | — | — | — | — | 266.9 | 266.9 | 278.3 | ||||||||||||||||
| Average interest rate (AUD) |
— | — | — | — | — | 3m BBSW | 3m BBSW | |||||||||||||||||
| Variable rate (EUR) |
— | — | — | — | 6.0 | 13.4 | 19.4 | 20.2 | ||||||||||||||||
| Average interest rate (EUR) |
— | — | — | — | 3m LIBOR | 6m LIBOR | 5m LIBOR | |||||||||||||||||
| Variable rate (JPY) |
— | 18.3 | — | — | — | — | 18.3 | 18.5 | ||||||||||||||||
| Average interest rate (JPY) |
— | 6m LIBOR | — | — | — | — | 6m LIBOR | |||||||||||||||||
| Total debt |
5,097.3 | 5,578.0 | ||||||||||||||||||||||
| Cross-currency swaps |
(0.4 | ) | 9.0 | — | — | (0.4 | ) | (33.7 | ) | (25.5 | ) | (43.2 | ) | |||||||||||
| 5,071.8 | 5,534.8 | |||||||||||||||||||||||
The disclosures represent the interest profile and currency profile of financial liabilities before the impact of derivative hedging instruments.
The average variable rates above, LIBOR, exclude margins. LIBOR is the London Inter Bank Offer Rate.
GBP – Pounds Sterling, USD – American Dollars, CAD – Canadian Dollars, CZK – Czech Koruna, DKK – Danish Krone, EUR – Euros, JPY – Japanese Yen, AUD – Australian Dollars. BMA is a weekly high grade market index comprised of 7-day tax exempt variable rate demand notes produced by municipal market data. MCBY is the Moody’s Corporate Bond Yield. It is derived from the pricing data of 100 corporate bonds in the US market, each with current outstandings of over $100 million and maturities of 30 years. BBSW is the Australian Bank Bill Rate.
Reference to ‘m’ in ‘m LIBOR’ and ‘m BBSW’ represents months.
| * | Fair value represents the fair value of the total debt excluding the fair value of related cross-currency swaps, details of which are set out in Note 20(g). |
ScottishPower Annual Report and Accounts 2003/04 111
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
20 Loans and other borrowings continued
(d) Interest rate analysis of financial liabilities
| At 31 March 2004 | At 31 March 2003 | |||||||||||
| GBP £m |
USD £m |
Total £m |
GBP £m |
USD £m |
Total £m | |||||||
| Fixed rate borrowings |
1,331.0 | 2,181.1 | 3,512.1 | 1,427.0 | 2,096.2 | 3,523.2 | ||||||
| Floating rate borrowings |
1,125.3 | 434.4 | 1,559.7 | 946.8 | 515.6 | 1,462.4 | ||||||
| 2,456.3 | 2,615.5 | 5,071.8 | 2,373.8 | 2,611.8 | 4,985.6 | |||||||
| Weighted average interest rate at which borrowings are fixed |
Weighted average period for is fixed | |||||||||||||||
| At 31 March 2004 |
At 31 March 2003 |
At 31 March 2004 |
At 31 March 2003 | |||||||||||||
| GBP % |
USD % |
GBP % |
USD % |
GBP Years |
USD Years |
GBP Years |
USD Years | |||||||||
| Fixed rate borrowings |
6.8 | 6.6 | 6.7 | 7.6 | 10 | 9 | 11 | 13 | ||||||||
All amounts in the analysis above take into account the effect of interest rate swaps and currency swaps used to convert underlying debt into sterling. This does not include currency swaps used as part of the hedging of the US net investment. Floating rate borrowings bear interest at rates based on LIBOR, certificate of deposit rates, interbank borrowing rates, prime rates or other short-term market rates. The average interest rates on short-term borrowings as at 31 March 2004 were as follows: GBP 4.1%, USD 1.2% (2003 3.6% and 1.4% respectively).
Based on the floating rate debt of £1,559.7 million at 31 March 2004 (2003 £1,462.4 million), a 100 basis point change in interest rates would result in a £15.6 million change in profit before tax for the year (2003 £14.6 million change).
Debt in the table above is reported by currency. In the past it has been reported split by the location of issue, which has been the same as the currency split. During the year the UK operations issued $700 million of convertible bonds which were not swapped into sterling.
(e) Financial assets
| Note |
At 31 March 2004 | At 31 March 2003 | |||||||||||||
| UK £m |
US £m |
Total £m |
UK £m |
US £m |
Total £m | ||||||||||
| Fixed rate financial assets |
(i | ) | 7.1 | 90.7 | 97.8 | 8.3 | 114.2 | 122.5 | |||||||
| Floating rate financial assets |
(i | ) | 1,274.5 | 108.6 | 1,383.1 | 542.7 | 157.9 | 700.6 | |||||||
| 1,281.6 | 199.3 | 1,480.9 | 551.0 | 272.1 | 823.1 | ||||||||||
| (i) | All financial assets in the UK are denominated in pounds sterling and those in the US are denominated in US dollars. |
Included within US fixed rate financial assets at 31 March 2004 are amounts receivable under finance leases of £200.2 million (2003 £262.4 million) less non-recourse finance of £109.5 million (2003 £148.2 million). The floating rate financial assets of the group’s UK and US operations are principally cash deposits of which £2.2 million in the UK and £nil in the US (2003 £2.2 million and £nil respectively) are subject to either a legal assignment or a charge in favour of a third party.
| Weighted average interest rate at which financial assets are fixed |
Weighted average period for is fixed | |||||||||||||||
| At 31 March 2004 |
At 31 March 2003 |
At 31 March 2004 |
At 31 March 2003 | |||||||||||||
| UK % |
US % |
UK % |
US % |
UK Years |
US Years |
UK Years |
US Years | |||||||||
| Fixed rate financial assets |
8.4 | 10.0 | 8.2 | 10.0 | 6 | 5 | 5 | 9 | ||||||||
All amounts in the analysis above take into account the effect of interest rate swaps and currency swaps. Floating rate investments pay interest at rates based on LIBOR, certificate of deposit rates, prime rates or other short-term market rates. The average interest rates on short-term financial assets as at 31 March 2004 were as follows: UK operations 3.9%, US operations 1.0% (2003 3.6% and 1.2% respectively).
Based on the floating rate financial assets of £1,383.1 million at 31 March 2004 (2003 £700.6 million), a 100 basis point change in interest rates would result in a £13.8 million change in profit before tax for the year (2003 £7.0 million). Based on the floating rate short-term bank and other deposits of £1,347.3 million at 31 March 2004 (2003 £664.6 million), a 100 basis point change in interest rates would result in a £13.5 million change in profit before tax for the year (2003 £6.6 million).
The fair values of the financial assets are not materially different from their book values.
The group also has certain equity investments which have been excluded from the disclosures above because they have no maturity date. As at 31 March 2004, the book value of these investments was £57.2 million (2003 £68.9 million) and the fair value was £55.2 million (2003 £59.8 million).
(f) Borrowing facilities
The group has the following undrawn committed borrowing facilities at 31 March 2004 in respect of which all conditions precedent have been met. Of the facilities shown £544.1 million ($1,000 million) (2003 £100.0 million) relate to UK operations. The remaining £435.3 million ($800 million) (2003 £506.1 million ($800 million)) relate to US operations. All facilities are floating rate facilities.
| At 31 March 2004 |
At 31 March 2003 | |||
| £m |
£m | |||
| Expiring within one year |
476.1 | 416.3 | ||
| Expiring between two and five years |
503.3 | 189.8 | ||
Commitment fees on the above facilities were as follows: UK operations £1.2 million (2003 £0.2 million); US operations £0.6 million (2003 £0.9 million).
112 ScottishPower Annual Report and Accounts 2003/04
20 Loans and other borrowings continued
(g) Maturity analysis of derivatives
| 2005 | 2006 | 2007 | 2008 | 2009 | Thereafter | Total | Fair Value* |
|||||||||||||||||
| £m |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
|||||||||||||||||
| Interest rate swaps |
||||||||||||||||||||||||
| Variable to fixed (GBP) |
175.0 | — | 50.0 | 68.7 | — | 50.0 | 343.7 | 10.2 | ||||||||||||||||
| Average pay rate |
4.7 | % | — | 5.5 | % | 6.4 | % | — | 6.3 | % | 5.4 | % | ||||||||||||
| Average receive rate |
6m LIBOR | — | 3m LIBOR | 6m LIBOR | — | 3m LIBOR | 5m LIBOR | |||||||||||||||||
| Fixed to index-linked (GBP) |
— | — | — | — | — | 100.0 | 100.0 | 14.3 | ||||||||||||||||
| Average pay rate |
— | — | — | — | — | 3.35 x RPI | 3.35 x RPI | |||||||||||||||||
| Average receive rate |
— | — | — | — | — | 6.2 | % | 6.2 | % | |||||||||||||||
| Fixed to variable (GBP) |
150.0 | 111.2 | 638.0 | 307.8 | 185.2 | 806.9 | 2,199.1 | (40.1 | ) | |||||||||||||||
| Average pay rate |
6m LIBOR | 6m LIBOR | 6m LIBOR | 6m LIBOR | 6m LIBOR | 6m LIBOR | 6m LIBOR | |||||||||||||||||
| Average receive rate |
5.7 | % | 5.0 | % | 5.2 | % | 5.4 | % | 5.4 | % | 6.7 | % | 5.8 | % | ||||||||||
| Variable to variable (GBP) |
5.0 | — | — | — | 30.0 | — | 35.0 | (0.6 | ) | |||||||||||||||
| Average pay rate |
6m LIBOR | — | — | — | 6m LIBOR | — | 6m LIBOR | |||||||||||||||||
| Average receive rate |
3m LIBOR | — | — | — | 12m LIBOR | — | 11m LIBOR | |||||||||||||||||
| Variable to fixed (USD) |
272.0 | 360.2 | 435.3 | 217.6 | — | 462.5 | 1,747.6 | 32.3 | ||||||||||||||||
| Average pay rate |
3.5 | % | 3.4 | % | 2.4 | % | 3.2 | % | — | 4.2 | % | 3.3 | % | |||||||||||
| Average receive rate |
6m LIBOR | 6m LIBOR | 6m LIBOR | 6m LIBOR | — | 6m LIBOR | 6m LIBOR | |||||||||||||||||
| Swaptions |
||||||||||||||||||||||||
| Notional amount (GBP) |
— | — | — | — | — | 100.0 | 100.0 | 2.4 | ||||||||||||||||
| Average pay rate |
— | — | — | — | — | 4.3 | % | 4.3 | % | |||||||||||||||
| Average receive rate |
— | — | — | — | — | 6m LIBOR | 6m LIBOR | |||||||||||||||||
| Cross-currency swaps |
||||||||||||||||||||||||
| Receive fixed USD pay variable GBP |
— | — | — | — | — | 51.4 | 51.4 | (6.5 | ) | |||||||||||||||
| Average pay rate (GBP) |
— | — | — | — | — | 6m LIBOR | 6m LIBOR | |||||||||||||||||
| Average receive rate (USD) |
— | — | — | — | — | 4.6 | % | 4.6 | % | |||||||||||||||
| Receive variable USD pay fixed GBP |
— | 33.1 | — | — | 21.2 | — | 54.3 | 9.2 | ||||||||||||||||
| Average pay rate (GBP) |
— | 6.7 | % | — | — | 4.9 | % | — | 6.0 | % | ||||||||||||||
| Average receive rate (USD) |
— | 3m LIBOR | — | — | 3m LIBOR | — | 3m LIBOR | |||||||||||||||||
| Receive variable USD pay variable GBP |
— | 33.3 | — | — | — | — | 33.3 | 6.3 | ||||||||||||||||
| Average pay rate (GBP) |
— | 6m LIBOR | — | — | — | — | 6m LIBOR | |||||||||||||||||
| Average receive rate (USD) |
— | 3m LIBOR | — | — | — | — | 3m LIBOR | |||||||||||||||||
| Receive variable AUD pay variable GBP |
— | — | — | — | — | 237.8 | 237.8 | (34.3 | ) | |||||||||||||||
| Average pay rate (GBP) |
— | — | — | — | — | 6m LIBOR | 6m LIBOR | |||||||||||||||||
| Average receive rate (AUD) |
— | — | — | — | — | 3m BBSW | 3m BBSW | |||||||||||||||||
| Receive fixed CZK pay variable GBP |
— | 34.3 | — | — | — | — | 34.3 | (8.7 | ) | |||||||||||||||
| Average pay rate (GBP) |
— | 6m LIBOR | — | — | — | — | 6m LIBOR | |||||||||||||||||
| Average receive rate (CZK) |
— | 6.9 | % | — | — | — | — | 6.9 | % | |||||||||||||||
| Receive fixed EUR pay fixed GBP |
— | — | — | — | 246.6 | — | 246.6 | (7.2 | ) | |||||||||||||||
| Average pay rate (GBP) |
— | — | — | — | 6.7 | % | — | 6.7 | % | |||||||||||||||
| Average receive rate (EUR) |
— | — | — | — | 5.3 | % | — | 5.3 | % | |||||||||||||||
| Receive fixed EUR pay variable GBP |
14.6 | — | — | — | 36.8 | — | 51.4 | (4.0 | ) | |||||||||||||||
| Average pay rate (GBP) |
6m LIBOR | — | — | — | 6m LIBOR | — | 6m LIBOR | |||||||||||||||||
| Average receive rate (EUR) |
4.8 | % | — | — | — | 5.0 | % | — | 4.9 | % | ||||||||||||||
| Receive variable EUR pay variable GBP |
— | — | — | — | 5.8 | 12.9 | 18.7 | (1.4 | ) | |||||||||||||||
| Average pay rate (GBP) |
— | — | — | — | 6m LIBOR | 6m LIBOR | 6m LIBOR | |||||||||||||||||
| Average receive rate (EUR) |
— | — | — | — | 3m LIBOR | 6m LIBOR | 5m LIBOR | |||||||||||||||||
| Receive variable JPY pay variable GBP |
— | 21.9 | — | — | — | — | 21.9 | 3.4 | ||||||||||||||||
| Average pay rate (GBP) |
— | 6m LIBOR | — | — | — | — | 6m LIBOR | |||||||||||||||||
| Average receive rate (JPY) |
— | 6m LIBOR | — | — | — | — | 6m LIBOR | |||||||||||||||||
| Receive fixed GBP pay fixed USD |
503.8 | — | — | — | — | — | 503.8 | (97.7 | ) | |||||||||||||||
| Average pay rate (USD) |
3.6 | % | — | — | — | — | — | 3.6 | % | |||||||||||||||
| Average receive rate (GBP) |
5.1 | % | — | — | — | — | — | 5.1 | % | |||||||||||||||
| Receive variable GBP pay fixed USD |
61.4 | 119.5 | — | — | — | — | 180.9 | (17.4 | ) | |||||||||||||||
| Average pay rate (USD) |
2.9 | % | 3.1 | % | — | — | — | — | 3.0 | % | ||||||||||||||
| Average receive rate (GBP) |
6m LIBOR | 6m LIBOR | — | — | — | — | 6m LIBOR | |||||||||||||||||
| Receive variable GBP pay variable USD |
105.3 | 277.7 | 523.7 | 409.0 | 270.1 | 677.9 | 2,263.7 | (62.5 | ) | |||||||||||||||
| Average pay rate (USD) |
6m LIBOR | 6m LIBOR | 6m LIBOR | 6m LIBOR | 6m LIBOR | 6m LIBOR | 6m LIBOR | |||||||||||||||||
| Average receive rate (GBP) |
6m LIBOR | 6m LIBOR | 6m LIBOR | 6m LIBOR | 6m LIBOR | 6m LIBOR | 6m LIBOR | |||||||||||||||||
| Forward contracts |
||||||||||||||||||||||||
| Buy GBP, sell USD |
912.4 | 349.5 | 446.4 | 157.7 | — | — | 1,866.0 | (130.5 | ) | |||||||||||||||
| Buy USD, sell GBP |
359.1 | 161.1 | 293.5 | 149.4 | — | — | 963.1 | 12.9 | ||||||||||||||||
| Buy CAD, sell USD |
6.1 | — | — | — | — | — | 6.1 | (0.1 | ) | |||||||||||||||
| Buy DKK, sell GBP |
42.8 | 5.1 | — | — | — | — | 47.9 | 0.3 | ||||||||||||||||
| 11,106.6 | (319.7 | ) | ||||||||||||||||||||||
The abbreviations contained in the table are defined in Note 20(c). The above table includes derivatives relating to the hedging of earnings and the net assets of the US business, hedging interest rate risk and foreign exchange risk on debt issues and hedging foreign exchange risk on a small number of business transactions.
| * | Derivatives which have a positive fair value are shown in the table above as bracketed, while derivatives with a negative fair value are shown without brackets to follow the convention in Note 20(b) that financial liabilities are shown without brackets. |
ScottishPower Annual Report and Accounts 2003/04 113
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
20 Loans and other borrowings continued
(h) Hedges
Gains and losses on instruments used for hedging are not recognised until the exposure that is being hedged is itself recognised. Unrecognised gains and losses on instruments used for hedging, and the movements therein, are as follows:
| Gains | Losses | Total net gains/ losses |
||||||||||
| Note |
£m |
£m |
£m |
|||||||||
| Unrecognised gains and (losses) on hedges at 1 April 2002 |
64.1 | (142.6 | ) | (78.5 | ) | |||||||
| Transfer from gains to losses |
(i | ) | (6.7 | ) | 6.7 | – | ||||||
| Transfer from losses to gains |
(i | ) | (49.4 | ) | 49.4 | – | ||||||
| (Gains) and losses arising in previous years that were recognised in 2002/03 |
(23.2 | ) | 4.1 | (19.1 | ) | |||||||
| Gains and (losses) arising before 1 April 2002 that were not recognised in 2002/03 |
(15.2 | ) | (82.4 | ) | (97.6 | ) | ||||||
| Gains and (losses) arising in 2002/03 that were not recognised in 2002/03 |
196.6 | (52.8 | ) | 143.8 | ||||||||
| Unrecognised gains and (losses) on hedges at 31 March 2003 |
181.4 | (135.2 | ) | 46.2 | ||||||||
| Gains and (losses) expected to be recognised in 2003/04 |
33.1 | (48.1 | ) | (15.0 | ) | |||||||
| Gains and (losses) expected to be recognised in 2004/05 or later |
148.3 | (87.1 | ) | 61.2 | ||||||||
| (i) | Figures in the table above are calculated by reference to the 31 March 2003 fair value of the derivative concerned. |
| Gains | Losses | Total net gains/ losses | |||||||||
| Note |
£m |
£m |
£m | ||||||||
| Unrecognised gains and (losses) on hedges at 1 April 2003 |
181.4 | (135.2 | ) | 46.2 | |||||||
| Transfer from gains to losses |
(ii | ) | – | – | – | ||||||
| Transfer from losses to gains |
(ii | ) | – | – | – | ||||||
| (Gains) and losses arising in previous years that were recognised in 2003/04 |
(32.4 | ) | 40.6 | 8.2 | |||||||
| Gains and (losses) arising before 1 April 2003 that were not recognised in 2003/04 |
149.0 | (94.6 | ) | 54.4 | |||||||
| Gains and (losses) arising in 2003/04 that were not recognised in 2003/04 |
32.0 | (18.0 | ) | 14.0 | |||||||
| Unrecognised gains and (losses) on hedges at 31 March 2004 |
181.0 | (112.6 | ) | 68.4 | |||||||
| Gains and (losses) expected to be recognised in 2004/05 |
56.6 | (34.3 | ) | 22.3 | |||||||
| Gains and (losses) expected to be recognised in 2005/06 or later |
124.4 | (78.3 | ) | 46.1 | |||||||
| (ii) | Figures in the table above are calculated by reference to the 31 March 2004 fair value of the derivative concerned. |
The analysis above excludes any gains and losses in respect of the net investment cross-currency swaps and net investment forward contracts and losses of £10.0 million relating to certain other forward contracts as gains and losses arising on these contracts will be recognised in the statement of total recognised gains and losses.
(i) Fair value of financial assets and liabilities held for trading
| 2004 | 2003 | |||||
| £m |
£m |
|||||
| Net realised and unrealised gains included in profit and loss account |
4.3 | 2.9 | ||||
| Fair value of financial assets held for trading at 31 March |
15.6 | 11.0 | ||||
| Fair value of financial liabilities held for trading at 31 March |
(15.0 | ) | (10.6 | ) | ||
In the UK and US a limited amount of proprietary trading within the limits and guidelines of the risk management framework is undertaken. The transactions included in the table above consist of forward purchase and sale contracts of electricity and forward purchase and sale contracts of gas and gas futures contracts. These contracts are marked to market value using externally derived market prices and any gain or loss arising is recognised in the profit and loss account. This is not in accordance with the provisions of Schedule 4 to the Companies Act 1985 which requires that these contracts be stated at the lower of cost and net realisable value or that, if revalued, any revaluation difference be taken to revaluation reserve. However, the directors consider that compliance with these requirements would lead to the Accounts failing to give a true and fair view of the results of the group since the marketability of energy trading contracts enables decisions to be made continually on whether to hold or sell them. Accordingly, the measurement of profit in any period is properly made by reference to market values. The effect of the departure on the Accounts is to increase the profit for the year by £4.6 million (2003 £7.3 million) and increase the group’s net assets by £15.6 million (2003 £11.0 million).
(j) Currency exposures
As explained in the Financial Review on pages 33 to 61 the group uses forward contracts, cross-currency swaps and borrowings in foreign currencies to mitigate the currency exposures arising from its overseas net investments. Gains and losses arising on overseas net investments and the forward contracts, cross-currency swaps and foreign currency borrowings used to hedge the currency exposures, are recognised in the statement of total recognised gains and losses.
Other than the transactions referred to above, the group did not hold material net monetary assets or liabilities in currencies other than functional currency at 31 March 2004 and 31 March 2003.
21 Other creditors
| 2004 | 2003 (As restated | |||
| £m |
£m | |||
| Amounts falling due within one year: |
||||
| Trade creditors |
131.3 | 135.9 | ||
| Corporate tax |
237.7 | 251.1 | ||
| Other taxes and social security |
54.4 | 62.6 | ||
| Payments received on account |
34.5 | 43.2 | ||
| Capital creditors and accruals |
87.8 | 73.0 | ||
| Other creditors |
241.5 | 388.1 | ||
| Accrued expenses |
758.6 | 691.2 | ||
| Proposed dividend |
112.9 | 132.2 | ||
| 1,658.7 | 1,777.3 | |||
114 ScottishPower Annual Report and Accounts 2003/04
22 Provisions for liabilities and charges – Deferred tax
Deferred tax provided in the Accounts is as follows:
| Provided | |||||
| 2004 | 2003 | ||||
| £m |
£m |
||||
| Accelerated capital allowances |
1,161.0 | 1,539.9 | |||
| Other timing differences |
81.2 | (238.0 | ) | ||
| 1,242.2 | 1,301.9 | ||||
| Note |
£m |
||||
| Deferred tax provided at 1 April 2001 |
1,625.3 | ||||
| Charge to profit and loss account |
70.2 | ||||
| Other movements |
(4.3 | ) | |||
| Deferred tax provided at 1 April 2002 |
1,691.2 | ||||
| Charge to profit and loss account |
50.6 | ||||
| Disposal of Southern Water |
32 | (361.0 | ) | ||
| Exchange |
(80.5 | ) | |||
| Other movements |
1.6 | ||||
| Deferred tax provided at 1 April 2003 |
1,301.9 | ||||
| Charge to profit and loss account |
74.4 | ||||
| Exchange |
(134.6 | ) | |||
| Other movements |
0.5 | ||||
| Deferred tax provided at 31 March 2004 |
1,242.2 | ||||
23 Provisions for liabilities and charges – Other provisions
| 2001/02 | At 1 April 2001 (as previously stated) |
Prior year adjustment for UITF 38 (Note 17) |
At 1 April 2001 (as restated) |
Demerger of Thus (Note 33) |
New provisions |
Unwinding of discount |
Utilised during year |
Exchange | At 31 March 2002 | |||||||||||||||
| £m |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
£m | ||||||||||||||||
| Reorganisation and restructuring |
85.1 | – | 85.1 | – | 18.5 | – | (40.8 | ) | (0.2 | ) | 62.6 | |||||||||||||
| Environmental and health |
96.8 | – | 96.8 | – | 0.1 | 5.7 | (4.4 | ) | – | 98.2 | ||||||||||||||
| Decommissioning costs |
82.1 | – | 82.1 | – | – | 4.8 | (0.3 | ) | – | 86.6 | ||||||||||||||
| Onerous contracts |
244.1 | – | 244.1 | – | – | 8.5 | (67.3 | ) | – | 185.3 | ||||||||||||||
| Pensions, post-retirement and post-employment benefits |
164.9 | – | 164.9 | – | 17.3 | – | (19.3 | ) | (0.2 | ) | 162.7 | |||||||||||||
| Mine reclamation costs |
90.3 | – | 90.3 | – | – | 3.8 | (9.1 | ) | (0.1 | ) | 84.9 | |||||||||||||
| Disposal of and withdrawal from Appliance Retailing |
– | – | – | – | 50.8 | – | (43.5 | ) | – | 7.3 | ||||||||||||||
| Other |
15.4 | (5.1 | ) | 10.3 | (0.9 | ) | 22.9 | – | (10.9 | ) | – | 21.4 | ||||||||||||
| 778.7 | (5.1 | ) | 773.6 | (0.9 | ) | 109.6 | 22.8 | (195.6 | ) | (0.5 | ) | 709.0 | ||||||||||||
| 2002/03 | At 1 April 2002 (as previously stated) |
Prior year adjustment for UITF 38 (Note 17) |
At 1 April 2002 (as restated) |
Disposal of Southern Water (Note 32) |
New provisions |
Unwinding of discount |
Utilised during year |
Exchange | At 31 March 2003 | |||||||||||||||
| £m |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
£m | ||||||||||||||||
| Reorganisation and restructuring |
62.6 | – | 62.6 | (2.5 | ) | 4.7 | – | (32.3 | ) | (3.0 | ) | 29.5 | ||||||||||||
| Environmental and health |
98.2 | – | 98.2 | (3.1 | ) | – | 9.5 | (10.9 | ) | (8.5 | ) | 85.2 | ||||||||||||
| Decommissioning costs |
86.6 | – | 86.6 | – | 0.5 | 4.8 | (0.6 | ) | (8.0 | ) | 83.3 | |||||||||||||
| Onerous contracts |
185.3 | – | 185.3 | – | – | 8.4 | (32.4 | ) | – | 161.3 | ||||||||||||||
| Pensions, post-retirement and post-employment benefits |
162.7 | – | 162.7 | – | 52.0 | – | (47.4 | ) | (17.0 | ) | 150.3 | |||||||||||||
| Mine reclamation costs |
84.9 | – | 84.9 | – | – | 3.8 | (8.1 | ) | (8.3 | ) | 72.3 | |||||||||||||
| Disposal of and withdrawal from Appliance Retailing |
7.3 | – | 7.3 | – | – | – | (2.1 | ) | – | 5.2 | ||||||||||||||
| Other |
26.2 | (4.8 | ) | 21.4 | – | 11.4 | – | (13.4 | ) | (0.9 | ) | 18.5 | ||||||||||||
| 713.8 | (4.8 | ) | 709.0 | (5.6 | ) | 68.6 | 26.5 | (147.2 | ) | (45.7 | ) | 605.6 | ||||||||||||
| 2003/04 | Notes | At 1 April 2003 (as previously stated) |
Prior year adjustment for UITF 38 (Note 17) |
At 1 April 2003 (as restated) |
New provisions |
Unwinding of discount |
Utilised during year |
Exchange | At 31 March 2004 | |||||||||||||||
| £m |
£m |
£m |
£m |
£m |
£m |
£m |
£m | |||||||||||||||||
| Reorganisation and restructuring |
(a | ) | 29.5 | – | 29.5 | 0.8 | – | (26.1 | ) | (1.0 | ) | 3.2 | ||||||||||||
| Environmental and health |
(b | ) | 85.2 | – | 85.2 | 0.1 | 4.1 | (18.5 | ) | (10.4 | ) | 60.5 | ||||||||||||
| Decommissioning costs |
(c | ) | 83.3 | – | 83.3 | 9.2 | 4.9 | (2.3 | ) | (10.8 | ) | 84.3 | ||||||||||||
| Onerous contracts |
(d | ) | 161.3 | – | 161.3 | – | 7.7 | (48.5 | ) | – | 120.5 | |||||||||||||
| Pensions, post-retirement and post-employment benefits |
(e | ) | 150.3 | – | 150.3 | 84.8 | – | (65.5 | ) | (22.2 | ) | 147.4 | ||||||||||||
| Mine reclamation costs |
(f | ) | 72.3 | – | 72.3 | 39.5 | 3.4 | (22.9 | ) | (12.7 | ) | 79.6 | ||||||||||||
| Disposal of and withdrawal from Appliance Retailing |
(g | ) | 5.2 | – | 5.2 | – | – | (3.4 | ) | – | 1.8 | |||||||||||||
| Other |
(h | ) | 23.8 | (5.3 | ) | 18.5 | 1.9 | – | (11.9 | ) | (1.3 | ) | 7.2 | |||||||||||
| 610.9 | (5.3 | ) | 605.6 | 136.3 | 20.1 | (199.1 | ) | (58.4 | ) | 504.5 | ||||||||||||||
ScottishPower Annual Report and Accounts 2003/04 115
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
23 Provisions for liabilities and charges – Other provisions continued
| (a) | The provision for reorganisation and restructuring principally comprises the reorganisation provision established in 2001/02 for the UK Division – Integrated Generation and Supply. This provision was expected to result in a reduction of employee numbers of approximately 500 from 2002/03 onwards. At 31 March 2004, the UK Division –Integrated Generation and Supply had reduced its employees by 390. The remaining provision relates to costs for a further reduction of 25 employees and other residual reorganisation expenses. |
| (b) | The environmental and health provisions principally comprise the costs of notified environmental remediation work and constructive obligations in respect of potential environmental remediation costs identified by an external due diligence review in the US. These costs are expected to be incurred in the period up to March 2010. Included within the ‘Unwinding of discount’ of £4.1 million (2003 £9.5 million, 2002 £5.7 million) is £1.7 million (2003 £3.9 million, 2002 £nil) relating to a change in the discount rate. |
| (c) | The provision for decommissioning costs is the discounted future estimated costs of decommissioning the group’s power plants, principally in the US, but also in the UK. The decommissioning of these plants is expected to occur over the period between 2005 and 2048. |
| (d) | The provision for onerous contracts comprises the costs of contracted energy purchases. The costs provided are expected to be incurred in the period up to 31 March 2009 as follows: less than 1 year £65.8 million, between 1 and 2 years £41.1 million and the remainder between 2 and 5 years £13.6 million. |
| (e) | Details of the group’s pensions, post-retirement and post-employment benefits are disclosed in Notes 28 and 34. |
| (f) | The provision for mine reclamation costs comprises the discounted future estimated costs of reclaiming the group’s mines in the US. The costs are expected to be incurred in the period up to 2031. |
| (g) | The Appliance Retailing provision comprises closure costs, principally property lease termination premia, expected to be incurred in the period up to 2005. |
| (h) | The Other category comprises various provisions which are not individually sufficiently material to warrant separate disclosure. |
24 Deferred income
| At 1 April 2002 |
Receivable during year |
Released to profit and loss account |
Disposal of Southern Water (Note 32) |
Exchange | At 31 March 2003 | ||||||||||
| £m |
£m |
£m |
£m |
£m |
£m | ||||||||||
| Grants and customer contributions |
551.2 | 68.7 | (18.6 | ) | (37.4 | ) | (5.0 | ) | 558.9 | ||||||
| At 1 April 2003 |
Receivable during year |
Released to profit and loss account |
Exchange | At 31 March 2004 | |||||||||||
| £m |
£m |
£m |
£m |
£m | |||||||||||
| Grants and customer contributions |
558.9 | 48.2 | (19.5 | ) | (9.8 | ) | 577.8 | ||||||||
25 Share capital
| 2004 | 2003 | ||||||
| Note |
£m |
£m | |||||
| Authorised: |
|||||||
| 3,000,000,000 (2003 3,000,000,000) ordinary shares of 50p each |
1,500.0 | 1,500.0 | |||||
| One Special Share of £1 |
(a | ) | – | – | |||
| 1,500.0 | 1,500.0 | ||||||
| Allotted, called up and fully paid: |
|||||||
| 1,859,538,923 (2003 1,855,932,802) ordinary shares of 50p each |
929.8 | 928.0 | |||||
| One Special Share of £1 |
(a | ) | – | – | |||
| 929.8 | 928.0 | ||||||
116 ScottishPower Annual Report and Accounts 2003/04
25 Share capital continued
(a) Special Share
The ‘Special Share’ was redeemed at par on 5 May 2004. The Special Share, which could be held only by one of the Secretaries of State or any other person acting on behalf of HM Government, did not carry rights to vote at the general or separate meetings but entitled the holder to attend and speak at such meetings. Written consent of the Special Shareholder was required before certain provisions of the company’s Articles of Association or certain rights attaching to the Special Share were varied. This share conferred no rights to participate in the capital or profits of the company, except that in a winding up the Special Shareholder was entitled to repayment in priority to the other shareholders.
(b) Employee share schemes
The group has six types of share based plans for employees. Options have been granted and awards made to eligible employees to subscribe for ordinary shares or ADSs in Scottish Power plc in accordance with the rules of each plan.
The ScottishPower Sharesave Schemes are savings related and under normal circumstances share options are exercisable on completion of a three or five year save-as-you-earn contract as appropriate.
The Executive Share Option Scheme applied to executive directors and certain senior managers. However, this Scheme was replaced with the Long Term Incentive Plan but options already granted were not affected.
The PacifiCorp Stock Incentive Plan (“PSIP”) relates to options over ScottishPower ADSs which vest over two or three years, as appropriate.
Awards granted under the Long Term Incentive Plan will vest only if the Remuneration Committee is satisfied that certain performance measures related to the sustained underlying financial performance of the group and improvements in customer service standards are achieved over a period of three financial years commencing with the financial year preceding the date an award is made.
Options granted under the Executive Share Option Plan 2001 (“ExSOP”) to executive directors and certain senior managers in the UK are subject to the performance criterion that the percentage increase in the company’s annualised earnings per share, excluding goodwill amortisation and exceptional items, be at least 3% (adjusted for any increase in the RPI). Options granted to US participants under the ExSOP, with the exception of the 2002 conditional award, are not subject to any performance criteria. The 2002 conditional award is subject to the same performance criterion as awards to UK participants.
The Employee Share Ownership Plan (“ESOP”) allows eligible employees to make contributions from pre-tax salary to buy shares in ScottishPower which are held in trust (Partnership Shares). These shares are matched by the company (Matching Shares) and are also held in trust. At the launch of the ESOP, Free Shares were offered to employees.
The K Plus Plan consists of the K Plus Employee Savings Plan and the K Plus Employee Stock Ownership Plan. The K Plan Employee Savings Plan is a 401(k) based qualified retirement plan designed to provide income during employees’ retirement. The K Plus Employee Stock Ownership Plan provides for matching contributions by PacifiCorp based on employees’ contributions, plus additional discretionary employer contributions made to all eligible employees.
(i) Summary of movements in share options in ScottishPower shares
| ScottishPower Sharesave Schemes |
Weighted (pence) |
Southern Water Sharesave Scheme |
Weighted (pence) |
Executive Share Option Schemes# |
Weighted (pence) |
PacifiCorp Stock Incentive Plan## |
Weighted (pence) |
Total | |||||||||||||||
| (number of shares 000s) |
(number of shares 000s) |
(number of shares 000s) |
(number of shares 000s) |
(number of shares 000s) |
|||||||||||||||||||
| Outstanding at 1 April 2001 |
16,212 | 355.6 | 279 | 149.3 | 140 | 316.1 | 14,908 | 588.8 | 31,539 | ||||||||||||||
| Granted |
4,378 | 386.0 | — | — | 2,354 | 483.0 | 3,299 | 452.1 | 10,031 | ||||||||||||||
| Exercised |
(6,718 | ) | 283.3 | (189 | ) | 144.7 | (78 | ) | 278.4 | (99 | ) | 474.3 | (7,084 | ) | |||||||||
| Lapsed |
(2,115 | ) | 420.6 | (7 | ) | 154.9 | (19 | ) | 483.0 | (2,240 | ) | 576.4 | (4,381 | ) | |||||||||
| Outstanding at 1 April 2002 |
11,757 | 396.7 | 83 | 159.1 | 2,397 | 479.9 | 15,868 | 563.6 | 30,105 | ||||||||||||||
| Granted |
3,316 | 323.0 | — | — | 7,327 | 388.0 | — | — | 10,643 | ||||||||||||||
| Exercised |
(1,992 | ) | 309.3 | (68 | ) | 159.4 | (16 | ) | 298.8 | — | — | (2,076 | ) | ||||||||||
| Lapsed |
(5,640 | ) | 409.3 | (15 | ) | 157.4 | (252 | ) | 411.1 | (2,255 | ) | 539.0 | (8,162 | ) | |||||||||
| Outstanding at 1 April 2003 |
7,441 | 377.7 | — | — | 9,456 | 411.5 | 13,613 | 500.8 | 30,510 | ||||||||||||||
| Granted |
2,758 | 301.0 | — | — | 5,892 | 352.8 | — | — | 8,650 | ||||||||||||||
| Exercised |
(17 | ) | 326.8 | — | — | (102 | ) | 320.3 | (590 | ) | 347.5 | (709 | ) | ||||||||||
| Lapsed |
(2,794 | ) | 392.3 | — | — | (34 | ) | 369.5 | (1,327 | ) | 469.9 | (4,155 | ) | ||||||||||
| Outstanding at 31 March 2004 |
7,388 | 343.6 | — | — | 15,212 | 376.5 | 11,696 | 430.4 | 34,296 | ||||||||||||||
| # | The Executive Share Option figures are a combination of the options outstanding under the Executive Share Option Scheme and the ExSOP. |
| ## | PacifiCorp Stock Incentive Plan are options over ScottishPower ADSs; for the purpose of the table above, ADSs have been converted to ScottishPower shares as follows: one ScottishPower ADS equals four ScottishPower ordinary shares. Eligibility for participation in the ExSOP was extended during the previous year to certain senior managers in the US. Consequently, no new options were granted in the prior year nor in the current year under the PSIP, nor is it intended to grant any new PSIP options in the future. |
ScottishPower Annual Report and Accounts 2003/04 117
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
25 Share capital continued
(ii) Analysis of share options outstanding at 31 March 2004
| Date of grant |
Number of participants |
Number (000s) |
Option (pence) |
Normal exercisable date |
|||||||
| ScottishPower Sharesave Schemes |
12 June 1998 | 22 | 18 | 440.0 | 6 months to March 2004 | ||||||
| 11 June 1999 | 731 | 674 | 429.0 | 6 months to March 2005 | |||||||
| 9 June 2000 | 447 | 312 | 453.0 | 6 months to March 2004 or 2006 | |||||||
| 8 June 2001 | 1,442 | 1,509 | 386.0 | 6 months to March 2005 or 2007 | |||||||
| 7 June 2002 | 1,588 | 2,295 | 323.0 | 6 months to March 2006 or 2008 | |||||||
| 6 June 2003 | 1,781 | 2,580 | 301.0 | 6 months to March 2007 or 2009 | |||||||
| Executive Share Option Scheme |
27 May 1994 | 1 | 1 | 354.0 | 1997-2004 | ||||||
| 12 May 1995 | 2 | 25 | 335.0 | 1998-2005 | |||||||
| Executive Share Option Plan 2001 |
21 August 2001 | 157 | 2,311 | 483.0 | 21 August 2004 to 21 August 2011 | ||||||
| UK: |
2 May 2002 | 129 | 3,351 | 406.0 | 2 May 2005 to 2 May 2012 | ||||||
| US standard*: |
2 May 2002 | 135 | 2,608 | 320.3 | 2 May 2003 to 2 May 2012 | ** | |||||
| US conditional*: |
2 May 2002 | 88 | 1,053 | 320.3 | 2 May 2005 to 2 May 2012 | ||||||
| UK: |
10 May 2003 | 136 | 2,768 | 376.3 | 10 May 2006 to 10 May 2013 | ||||||
| US*: |
10 May 2003 | 153 | 3,095 | 331.9 | 10 May 2004 to 10 May 2013 | ** | |||||
| PacifiCorp Stock Incentive Plan |
3 June 1997 | 46 | 664 | 463.3 | 29 November 1999 to 3 June 2007 | ||||||
| 12 August 1997 | 13 | 140 | 498.4 | 29 November 1999 to 12 August 2007 | |||||||
| 10 February 1998 | 67 | 1,169 | 562.8 | 29 November 1999 to 10 February 2008 |
| ||||||
| 13 May 1998 | 4,588 | 1,057 | 543.9 | 29 November 1999 to 13 May 2008 | |||||||
| 9 February 1999 | 79 | 2,052 | 445.6 | 9 February 2000 to 9 February 2009 | ** | ||||||
| 11 May 1999 | 4,844 | 1,114 | 403.2 | 11 May 2000 to 11 May 2009 | *** | ||||||
| 16 February 2000 | 86 | 1,695 | 366.4 | 16 February 2001 to 16 February 2010 | ** | ||||||
| 24 March 2000 | 4 | 1,343 | 431.9 | 24 March 2001 to 24 March 2010 | **** | ||||||
| 25 January 2001 | 1 | 230 | 340.9 | 25 January 2002 to 25 January 2011 | ** | ||||||
| 24 April 2001 | 102 | 2,232 | 349.6 | 24 April 2002 to 24 April 2011 | ** | ||||||
| * | Options granted under the Executive Share Option Plan 2001 to US based participants and options granted under the PacifiCorp Stock Incentive Plan are over ScottishPower ADSs. For the purpose of the table above, such options have been converted to ScotishPower ordinary shares as follows: one ScottishPower ADS equals four ScottishPower ordinary shares. The US$ ADS option exercise price was converted so that it may be represented in terms of ScottishPower ordinary shares. The price was further converted at the closing exchange rate on 31 March 2004 to be quoted in pence in the table above. Eligibility for participation in the Executive Share Option Plan 2001 was extended during the prior year to executive directors and certain senior managers in the US. Consequently, no new options were granted in the year under the PacifiCorp Stock Incentive Plan nor is it intended to grant any new PacifiCorp Stock Incentive Plan options in the future. |
| ** | Options become exercisable in the following proportions: one third on the first anniversary of grant, a further one third on the second anniversary of grant, and the final one third on the third anniversary of grant. |
| *** | Options became exercisable in the proportions 50% on 11 May 2000 and the remaining 50% on 11 May 2001. |
| **** | Options became exercisable in the following proportions: one quarter after 1 September 2001, one quarter after 1 September 2002 and the remaining one half after 1 September 2003. |
Where reference is made to PacifiCorp Stock Incentive Plan, this is to identify the plan under which the options over ScottishPower ADSs have been granted. For the PacifiCorp Stock Incentive Plan, the date of grant refers to the date the original PacifiCorp Common Stock options were granted. These options were exchanged for options over ScottishPower ADSs following the acquisition on 29 November 1999.
(iii) Shares in the company held under trust during the year are as follows:
| 2002/03 |
Dividends | Shares held at 1 April 2002 |
Shares acquired during year |
Shares transferred during year |
Shares held at 31 March 2003 |
Nominal value at 31 March 2003 |
Market value at 31 March 2003 | |||||||||||
| Notes |
waived |
(000s) |
(000s) |
(000s) |
(000s) |
£m |
£m | |||||||||||
| Long Term Incentive Plan |
(a | ) | no | 3,688 | — | (218 | ) | 3,470 | 1.7 | 13.0 | ||||||||
| ScottishPower Sharesave Schemes |
(b | ) | yes | 8,323 | — | (2,064 | ) | 6,259 | 3.1 | 23.5 | ||||||||
| Executive Share Option Plan 2001 |
(c | ) | yes | 2,360 | 7,387 | — | 9,747 | 4.9 | 36.6 | |||||||||
| PacifiCorp Stock Incentive Plan |
(d | ) | no | 160 | — | (54 | ) | 106 | 0.1 | 0.4 | ||||||||
| Employee Share Ownership Plan |
(e | ) | no | 2,182 | 1,574 | (755 | ) | 3,001 | 1.5 | 11.3 | ||||||||
| 16,713 | 8,961 | (3,091 | ) | 22,583 | 11.3 | 84.8 | ||||||||||||
| 2003/04 |
Dividends | Shares held at 1 April 2003 |
Shares acquired during year |
Shares transferred during year |
Shares held at 31 March 2004 |
Nominal value at 31 March 2004 |
Market value at 31 March 2004 | |||||||||||
| Notes |
waived |
(000s) |
(000s) |
(000s) |
(000s) |
£m |
£m | |||||||||||
| Long Term Incentive Plan |
(a | ) | no | 3,470 | 664 | (155 | ) | 3,979 | 2.0 | 15.2 | ||||||||
| ScottishPower Sharesave Schemes |
(b | ) | yes | 6,259 | — | (16 | ) | 6,243 | 3.1 | 23.8 | ||||||||
| Executive Share Option Plan 2001 |
(c | ) | yes | 9,747 | 5,901 | (102 | ) | 15,546 | 7.8 | 59.2 | ||||||||
| PacifiCorp Stock Incentive Plan |
(d | ) | no | 106 | — | (47 | ) | 59 | — | 0.2 | ||||||||
| Employee Share Ownership Plan |
(e | ) | no | 3,001 | 1,404 | (590 | ) | 3,815 | 1.9 | 14.5 | ||||||||
| 22,583 | 7,969 | (910 | ) | 29,642 | 14.8 | 112.9 | ||||||||||||
118 ScottishPower Annual Report and Accounts 2003/04
25 Share capital continued
| (a) | Shares of the company are held under trust as part of the Long Term Incentive Plan for executive directors and other senior managers (see Remuneration Report of the Directors on pages 72 to 83 for details of the Plan). |
| (b) | Shares of the company are held in two Qualifying Employee Share Ownership Trusts as part of the Scottish Power UK plc Sharesave Scheme and the Scottish Power plc Sharesave Scheme. Holders of options granted under the schemes will be awarded shares by the Trusts upon the exercise of the options. Details of options granted under these schemes are disclosed above. |
| (c) | Shares of the company are held under trust as part of the Executive Share Option Plan 2001 for executive directors and other senior managers (see Remuneration Report of the Directors on pages 72 to 83 for details of the plan). |
| (d) | Options granted under the PacifiCorp Stock Incentive Plan are for ScottishPower ADSs; for the purposes of the table above, ADS options have been converted to ScottishPower ordinary share options as follows: one ScottishPower ADS option equals four ScottishPower ordinary share options. |
| (e) | Shares of the company are held in the Employee Share Ownership Plan Trust on behalf of employees of the ScottishPower group. Shares appropriated under the Free Element and the Matching Element are subject to forfeiture for a period of three years from the date of appropriation. Shares appropriated under the Partnership Element of the Employee Share Ownership Plan are not subject to forfeiture. |
26 Analysis of movements in shareholders’ funds
| Number of shares |
Share capital |
Share premium |
Revaluation reserve |
Capital redemption reserve |
Merger reserve |
Other reserve |
Profit and loss account |
Total | |||||||||||||||||
| Notes |
000s |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
||||||||||||||||
| At 1 April 2001 – as originally stated |
1,849,026 | 924.5 | 3,739.7 | 217.1 | 18.3 | 406.4 | — | 587.2 | 5,893.2 | ||||||||||||||||
| Prior year adjustment for UITF 38 |
17 | — | — | — | — | — | — | — | (60.3 | ) | (60.3 | ) | |||||||||||||
| At 1 April 2001 – as restated |
1,849,026 | 924.5 | 3,739.7 | 217.1 | 18.3 | 406.4 | — | 526.9 | 5,832.9 | ||||||||||||||||
| Retained loss for the year |
— | — | — | — | — | — | — | (1,927.2 | ) | (1,927.2 | ) | ||||||||||||||
| Share capital issued |
|||||||||||||||||||||||||
| – Employee sharesave scheme |
99 | 0.1 | 0.5 | — | — | — | — | — | 0.6 | ||||||||||||||||
| – Executive share option scheme |
78 | — | 0.2 | — | — | — | — | — | 0.2 | ||||||||||||||||
| – ESOP |
3,444 | 1.7 | 13.7 | — | — | — | — | — | 15.4 | ||||||||||||||||
| Consideration paid in respect of purchase of own shares held under trust |
— | — | — | — | — | — | — | (25.6 | ) | (25.6 | ) | ||||||||||||||
| Credit in respect of employee share awards |
— | — | — | — | — | — | — | 2.5 | 2.5 | ||||||||||||||||
| Consideration received in respect of sale of own shares held under trust |
— | — | — | — | — | — | — | 19.8 | 19.8 | ||||||||||||||||
| Goodwill realised on disposals |
(b) | — | — | — | — | — | — | — | 753.3 | 753.3 | |||||||||||||||
| Goodwill realised on demerger of Thus |
33 | — | — | — | — | — | — | — | 14.7 | 14.7 | |||||||||||||||
| Reduction of share premium |
(c) | — | — | (1,500.0 | ) | — | — | — | — | 1,500.0 | — | ||||||||||||||
| Unrealised gains on fixed asset disposals |
— | — | — | — | — | — | 4.9 | — | 4.9 | ||||||||||||||||
| Gains realised on Thus demerger |
— | — | — | — | — | — | (4.9 | ) | 4.9 | — | |||||||||||||||
| Revaluation surplus realised |
— | — | — | (3.4 | ) | — | — | — | 3.4 | — | |||||||||||||||
| Fixed asset revaluation gains realised on disposal |
— | — | — | (168.2 | ) | — | — | — | 168.2 | — | |||||||||||||||
| Exchange movement on translation of overseas results and net assets |
(d) | — | — | — | — | — | — | — | (4.2 | ) | (4.2 | ) | |||||||||||||
| Translation differences on foreign currency hedging |
(d) | — | — | — | — | — | — | — | (19.5 | ) | (19.5 | ) | |||||||||||||
| At 1 April 2002 – as originally stated |
1,852,647 | 926.3 | 2,254.1 | 45.5 | 18.3 | 406.4 | — | 1,080.8 | 4,731.4 | ||||||||||||||||
| Prior year adjustment for UITF 38 |
17 | — | — | — | — | — | — | — | (63.6 | ) | (63.6 | ) | |||||||||||||
| At 1 April 2002 – as restated |
1,852,647 | 926.3 | 2,254.1 | 45.5 | 18.3 | 406.4 | — | 1,017.2 | 4,667.8 | ||||||||||||||||
| Retained loss for the year |
— | — | — | — | — | — | — | (46.9 | ) | (46.9 | ) | ||||||||||||||
| Share capital issued |
|||||||||||||||||||||||||
| – Executive share option scheme |
15 | — | 0.1 | — | — | — | — | — | 0.1 | ||||||||||||||||
| – ESOP |
3,271 | 1.7 | 10.2 | — | — | — | — | — | 11.9 | ||||||||||||||||
| Consideration paid in respect of purchase of own shares held under trust |
— | — | — | — | — | — | — | (36.2 | ) | (36.2 | ) | ||||||||||||||
| Credit in respect of employee share awards |
— | — | — | — | — | — | — | 10.0 | 10.0 | ||||||||||||||||
| Consideration received in respect of sale of own shares held under trust |
— | — | — | — | — | — | — | 6.4 | 6.4 | ||||||||||||||||
| Revaluation surplus realised |
— | — | — | (2.0 | ) | — | — | — | 2.0 | — | |||||||||||||||
| Exchange movement on translation of overseas results and net assets |
(d) | — | — | — | — | — | — | — | (387.0 | ) | (387.0 | ) | |||||||||||||
| Translation differences on foreign currency hedging |
(d) | — | — | — | — | — | — | — | 357.6 | 357.6 | |||||||||||||||
| Tax on translation differences on foreign currency hedging |
— | — | — | — | — | — | — | (28.8 | ) | (28.8 | ) | ||||||||||||||
| At 1 April 2003 - as originally stated |
1,855,933 | 928.0 | 2,264.4 | 43.5 | 18.3 | 406.4 | — | 977.7 | 4,638.3 | ||||||||||||||||
| Prior year adjustment for UITF 38 |
17 | — | — | — | — | — | — | — | (83.4 | ) | (83.4 | ) | |||||||||||||
| At 1 April 2003 – as restated |
1,855,933 | 928.0 | 2,264.4 | 43.5 | 18.3 | 406.4 | — | 894.3 | 4,554.9 | ||||||||||||||||
| Retained profit for the year |
— | — | — | — | — | — | — | 162.8 | 162.8 | ||||||||||||||||
| Share capital issued |
|||||||||||||||||||||||||
| – ESOP |
3,044 | 1.5 | 9.6 | — | — | — | — | — | 11.1 | ||||||||||||||||
| – PacifiCorp Stock Incentive Plan |
562 | 0.3 | 1.7 | — | — | — | — | — | 2.0 | ||||||||||||||||
| Consideration paid in respect of purchase of own shares held under trust |
— | — | — | — | — | — | — | (28.9 | ) | (28.9 | ) | ||||||||||||||
| Credit in respect of employee share awards |
— | — | — | — | — | — | — | 4.9 | 4.9 | ||||||||||||||||
| Consideration received in respect of sale of own shares held under trust |
— | — | — | — | — | — | — | 0.4 | 0.4 | ||||||||||||||||
| Revaluation surplus realised |
— | — | — | (1.9 | ) | — | — | — | 1.9 | — | |||||||||||||||
| Exchange movement on translation of overseas results and net assets |
(d) | — | — | — | — | — | — | — | (537.6 | ) | (537.6 | ) | |||||||||||||
| Translation differences on foreign currency hedging |
(d) | — | — | — | — | — | — | — | 475.2 | 475.2 | |||||||||||||||
| Tax on translation differences on foreign currency hedging |
(e) | — | — | — | — | — | — | — | 46.1 | 46.1 | |||||||||||||||
| Balance at 31 March 2004 |
1,859,539 | 929.8 | 2,275.7 | 41.6 | 18.3 | 406.4 | — | 1,019.1 | 4,690.9 | ||||||||||||||||
ScottishPower Annual Report and Accounts 2003/04 119
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
26 Analysis of movements in shareholders’ funds continued
| (a) | Cumulative goodwill written off to the profit and loss account reserve as at 31 March 2004 was £572.3 million (2003 £572.3 million, 2002 £572.3 million). |
| (b) | The goodwill realised on disposals related to Appliance Retailing (£15.1 million) and the impairment of goodwill in connection with the provision for loss on disposal of Southern Water (£738.2 million). |
| (c) | The company applied to the Court of Session (“the Court”) to approve a reduction in the share premium account which had previously been approved by the company’s shareholders at an Extraordinary General Meeting on 21 January 2002. On 5 March 2002, the Court approved the reduction of the company’s share premium account by £1,500 million. This amount was transferred to the company’s profit and loss account reserve. The reduction in the share premium account created sufficient distributable reserves to facilitate payment of a dividend in specie to demerge Thus. |
| (d) | The pre-tax cumulative foreign currency translation adjustments at 31 March 2004 amount to £402.5 million (2003 £464.9 million, 2002 £494.3 million). |
| (e) | The £46.1 million represents £48.0 million arising as a result of the application of the transitional rules contained in the Finance Act 2002, Schedule 26 and £(1.9) million for tax charged on derivative movements. |
27 Minority interests
| Equity 2004 |
Non-equity 2004 |
Total 2004 |
Equity 2003 |
Non-equity 2003 |
Total 2003 |
||||||||||||
| £m |
£m |
£m |
£m |
£m |
£m |
||||||||||||
| At 1 April |
2.0 | 71.9 | 73.9 | 1.5 | 85.2 | 86.7 | |||||||||||
| Redemption of preferred stock of PacifiCorp |
– | (4.6 | ) | (4.6 | ) | – | (5.1 | ) | (5.1 | ) | |||||||
| Profit and loss account |
1.7 | 4.1 | 5.8 | 0.5 | 4.7 | 5.2 | |||||||||||
| Dividends paid to minority interests |
(0.3 | ) | (4.3 | ) | (4.6 | ) | – | (4.8 | ) | (4.8 | ) | ||||||
| Exchange |
– | (9.6 | ) | (9.6 | ) | – | (8.1 | ) | (8.1 | ) | |||||||
| At 31 March |
3.4 | 57.5 | 60.9 | 2.0 | 71.9 | 73.9 | |||||||||||
Non-equity minority interests include 100% of the preferred stock and preferred stock subject to mandatory redemption of PacifiCorp. Of the total preferred stock subject to mandatory redemption at 31 March 2004, £2.0 million is due to be redeemed within 1 year, £2.0 million is due to be redeemed in each of the next 2 years with the remaining £26.5 million being redeemable after 3 years. Of the total preferred stock subject to mandatory redemption at 31 March 2003, £2.3 million was due to be redeemed within 1 year, £2.3 million was due to be redeemed in each of the next 3 years and the remaining £32.8 million was redeemable after 4 years.
The fair value of preferred stock subject to mandatory redemption is £36.9 million (2003 £49.4 million). The fair value of other preferred stock is not materially different from its book value.
The weighted average rate of return on preferred stock subject to mandatory redemption is 7.5% (2003 7.6%) and on other preferred stock is 5.1% (2003 5.1%).
Preferred stockholders have first preference in the event of a liquidation of PacifiCorp and first rights to dividends. The holders of these shares only have rights against the PacifiCorp group of companies.
28 Pensions and other post-retirement benefits
At 31 March 2004, ScottishPower had six statutorily approved defined benefit pension schemes, one statutorily approved defined contribution scheme and one unapproved scheme. Details of the principal schemes are set out below:
| Funded or |
Pension charge for the year |
Provision as at 31 March |
||||||||||||||
| 2004 | 2003 | 2002 | 2004 | 2003 | ||||||||||||
| Pension fund |
Scheme type |
unfunded |
£m |
£m |
£m |
£m |
£m |
|||||||||
| ScottishPower |
Defined benefit | funded | 13.2 | 7.0 | – | (2.0 | ) | (2.0 | ) | |||||||
| Manweb |
Defined benefit | funded | 8.8 | 5.2 | 3.6 | (2.9 | ) | – | ||||||||
| Final Salary LifePlan |
Defined benefit | funded | 3.7 | 3.1 | 3.4 | – | – | |||||||||
| PacifiCorp(i), (ii) |
Defined benefit | funded | 38.4 | 25.6 | 7.5 | (87.3 | ) | (83.6 | ) | |||||||
| (i) | The PacifiCorp figures include the unfunded Supplementary Executive Retirement Plan (“SERP”). The SERP accounts for less than 5% of the PacifiCorp liabilities. |
| (ii) | The PacifiCorp figures for 2004 include a £3.1 million (2003 £3.1 million) contribution to the PacifiCorp/International Brotherhood of Electrical Workers (“IBEW”) Local Union 57 Retirement Trust Fund. The PacifiCorp figures for 2003 included a credit adjustment of £2.5 million (2002 £0.6 million charge) to Special Termination Benefits. |
The components of the pension charge are as follows:
| 2004 | 2003 | ||||||||||||||||||
| Regular cost |
Interest cost on provision |
Variation (credit)/ cost |
Net pension charge |
Regular cost |
Interest (credit)/ |
Variation (credit)/ cost |
Net pension charge | ||||||||||||
| Pension fund |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
£m | |||||||||||
| ScottishPower |
18.5 | 0.1 | (5.4 | ) | 13.2 | 17.9 | (0.3 | ) | (10.6 | ) | 7.0 | ||||||||
| Manweb |
5.5 | – | 3.3 | 8.8 | 6.0 | – | (0.8 | ) | 5.2 | ||||||||||
| Final Salary LifePlan |
3.7 | – | – | 3.7 | 3.1 | – | – | 3.1 | |||||||||||
| PacifiCorp |
14.0 | 4.8 | 19.6 | 38.4 | 13.5 | 5.8 | 6.3 | (i) | 25.6 | ||||||||||
| (i) | Being a normal variation cost of £8.8 million decreased by the credit adjustment relating to the Special Termination Benefits of £2.5 million. |
120 ScottishPower Annual Report and Accounts 2003/04
28 Pensions and other post-retirement benefits continued
The provision as at the year end can be reconciled as follows:
| Provision at 1 April |
Employer contribution |
Pension charge |
Exchange | Provision at 31 March 2004 |
Prepayment/ (provision) at 1 April |
Employer contribution |
Pension charge |
Exchange | Provision at 31 March 2003 |
|||||||||||||||||
| Pension fund |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
£m |
||||||||||||||||
| ScottishPower |
(2.0 | ) | 13.2 | (13.2 | ) | — | (2.0 | ) | 5.0 | — | (7.0 | ) | — | (2.0 | ) | |||||||||||
| Manweb |
— | 5.9 | (8.8 | ) | — | (2.9 | ) | — | 5.2 | (5.2 | ) | — | — | |||||||||||||
| Final Salary LifePlan |
— | 3.7 | (3.7 | ) | — | — | — | 3.1 | (3.1 | ) | — | — | ||||||||||||||
| PacifiCorp(i) |
(83.6 | ) | 23.0 | (38.4 | ) | 11.7 | (87.3 | ) | (88.4 | ) | 21.5 | (25.6 | ) | 8.9 | (83.6 | ) |
| (i) | The employer contribution rate to the PacifiCorp Scheme increased from 10.3% of pensionable salaries in 2002/03 to 11.2% of pensionable salaries in 2003/04. |
The individual scheme funding details based on the latest formal actuarial valuations (or later formal review) are as follows:
| Latest formal | Valuation carried out |
Value of assets based on valuation |
Market value of assets |
Valuation | Principal actuarial assumptions | |||||||||||||||||
| Average investment rate of |
Average salary |
Average pension |
Value of fund assets/ accrued |
|||||||||||||||||||
| Pension fund |
actuarial valuation |
by |
£m |
£m |
method adopted |
return |
increases |
increases |
benefits |
|||||||||||||
| ScottishPower(i) |
30 September 2003 | Mercer HR Consulting | 1,466.1 | 1,466.1 | Projected unit | 6.0 | % | 4.1 | % | 2.6 | % | 105 | % | |||||||||
| Manweb(i) |
30 September 2003 | Mercer HR Consulting | 508.7 | 508.7 | Projected unit | 6.0 | % | 4.1 | % | 2.6 | % | 93 | % | |||||||||
| Final Salary LifePlan |
31 March 2002 | Mercer HR Consulting | 4.8 | 4.8 | Projected unit | 6.0 | % | 4.3 | % | 2.8 | % | 94 | % | |||||||||
| PacifiCorp |
1 January 2003 | Hewitt Associates | 368.8 | 368.8 | Projected unit | 8.75 | %/6.75%(ii) | 4.0 | % | — | 65 | % | ||||||||||
| (i) | The most recent formal actuarial scheme valuations were carried out as at 31 March 2003 for ScottishPower and as at 31 March 2001 for Manweb. The valuation results shown are for later formal reviews requested by the company. |
| (ii) | 8.75% represents the expected return on assets and 6.75% represents the liability discount rate. |
(a) Group pension arrangements
Following a review of the group’s UK pension arrangements, the ScottishPower Pension Scheme and Manweb Pension Scheme were closed to new members from 31 December 1998.
The group introduced two new group pension plans for new UK employees effective from 1 January 1999. The new plans were a defined benefit plan (Final Salary LifePlan) which is open to continuous contract employees aged between 16 and 60, and a defined contribution plan (Money Purchase LifePlan) which was subsequently closed to new entrants with effect from 31 August 2003 and is currently in the process of being wound up with all assets and liabilities to be transferred to the Final Salary LifePlan.
The result of these changes in the UK pension arrangements is that the age profile of the two closed defined benefit schemes is expected to rise over time, due to the lack of new entrants. This will in turn result in increasing service costs for these two schemes due to the method of actuarial valuation used (the projected unit method). However, the same method is also used for the Final Salary LifePlan, which is open to new members and whose age profile is not expected to rise significantly in the short to medium term. Overall, the group believes that the projected unit method is appropriate when adopted across all schemes (closed and open), and in aggregate provides a reasonable basis for assessing the group’s pension costs.
Further details of the US arrangements are given in sub-note (f) below.
Each of the pension schemes are invested in an appropriately diversified range of equities, bonds, property and private markets. The broad proportions of each asset class in which the schemes aim to be invested are as follows, however it is important to note that this may vary from time to time as markets change and as cash may be held for strategic reasons.
| Equities | Bonds | Property | Private markets |
Total | ||||||
| % |
% |
% |
% |
% | ||||||
| ScottishPower |
65 | 29 | 6 | — | 100 | |||||
| Manweb |
65 | 35 | — | — | 100 | |||||
| Final Salary LifePlan |
100 | — | — | — | 100 | |||||
| PacifiCorp (pension) |
55 | 34 | — | 11 | 100 | |||||
| PacifiCorp (healthcare) |
63 | 35 | — | 2 | 100 |
In broad terms, the investment strategies adopted by the schemes aim to ensure that sufficient assets are available to meet scheme liabilities as they fall due. The ScottishPower and Manweb schemes’ investment strategies reflect the large and growing proportion of their liabilities which relate to pensions in payment, and therefore include a growing bond element. A significant equity element is still retained, however, to provide potential for long-term outperformance relative to bonds and therefore to reduce the group’s contribution requirements. For the Final Salary LifePlan, the strategy remains 100% equities due to its young membership with on average over 20 years’ duration until retirement: with such a long-term until liabilities fall due, the group and trustees have agreed that a fully equity-oriented strategy remains appropriate.
US arrangements are managed and invested in accordance with all applicable requirements, including the Employee Retirement Income Security Act (“ERISA”) and the Internal Revenue Service (“IRS”) revenue code (the ERISA is the US legislation which regulates pension institutions in a number of areas). PacifiCorp employs an investment approach whereby a mix of equities and fixed income investments are used to maximise the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed income investments. Equity investments are diversified across US and non-US stocks, as well as growth, value, small and large capitalisation. Fixed income investments are diversified across US and non-US bonds. Other assets such as private equity are used judiciously to enhance long-term returns while improving portfolio diversification. PacifiCorp primarily minimises the risk of large losses through diversification but also monitors and manages other aspects of risk through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.
ScottishPower Annual Report and Accounts 2003/04 121
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
28 Pensions and other post-retirement benefits continued
(b) ScottishPower
Scottish Power UK plc operates a funded pension scheme of the company providing defined retirement and death benefits based on final pensionable salary. This scheme was open prior to 1 January 1999 to employees of ScottishPower. Members are required to contribute to the Scheme at a rate of 5% of pensionable salary. Scottish Power UK plc meets the balance of cost of providing benefits, and company contributions paid are based on the results of the formal actuarial valuation of the Scheme and are agreed by Scottish Power UK plc and the Scheme Trustees.
The assets of the Scheme are held separately from those of the company in a trustee administered fund. Included in the Scheme assets are 116,797 ScottishPower shares (£444,705, based on market value as at 31 March 2004), purchased only as part of a pooled strategy to match the relative weightings in the UK Stock Exchange index.
The pension charge for the year is based on the advice of the Scheme’s independent qualified actuary and is calculated using assumptions that were applied to a formal review of the Scheme at 30 September 2003.
The amount included in the balance sheet represents the difference between the accumulated excess of the actual contributions paid to the Scheme and the pension accounting charge. The net pension charge is derived from a regular cost of 21.1% of salaries, offset by a variation credit of 6.1% of salaries. The variation credit is calculated as the assessed surplus, as adjusted for the balance sheet amount, spread as a fixed percentage of pensionable salaries over 13 years.
Following the formal actuarial valuation of the Scheme as at 31 March 2003, employer contributions of 15% of pensionable salaries were reinstated from that date.
(c) Manweb
Prior to 1 January 1999, most of the Manweb employees were entitled to join the Manweb Group of the Electricity Supply Pension Scheme, which provides pension and other related benefits based on final pensionable salary to employees throughout the Electricity Supply Industry in England & Wales. The ongoing contributions to the Scheme are based on the results of the formal actuarial valuation of the Scheme and the advice of the Scheme Actuary.
The assets are held in a separate trustee administered fund. The Scheme assets no longer include any ScottishPower shares. For funding and expensing purposes the Scheme assets are taken at market value plus a smoothing adjustment appropriate at the valuation date.
The pension charge for the year is based on advice from an independent qualified actuary and is calculated using assumptions that were applied to a formal review of the Scheme as at 30 September 2003.
The net pension charge is derived from a regular cost of 13.9% of salaries, increased by a variation cost of 8.1% of salaries. The variation cost is calculated as the assessed deficit at the valuation date, spread as a fixed percentage of pensionable salaries over 13 years.
The actual contributions payable by participating employers during the year ranged between 8.1% and 14.1% for different sections of membership (but tending towards the higher rates), or other rates for particular groups or as required by a business transfer agreement. The rates of contributions payable will be reviewed following the results of the formal actuarial valuation of the Scheme as at 31 March 2004.
(d) Southern Water
The sale of Southern Water to First Aqua Limited (“First Aqua”) was concluded on 23 April 2002. The figures in this Note relate purely to the charge arising prior to this date. There is no impact in respect of pensions on the group’s balance sheet as a result of the sale of Southern Water, as the Southern Water Scheme had not given rise to any prepayment or provision at the time of the sale.
Southern Water operated a funded pension scheme. Members were required to contribute to the Scheme at varying rates of pensionable salary depending upon category of membership. The company met the balance of the cost of the accruing benefits. Contributions paid were based on the results of the formal actuarial valuation of the Scheme and were agreed by the company and the Scheme Trustees.
The assets were held in a separate trustee administered fund. For funding and expensing purposes, the Scheme assets were taken at market value.
The pension charge for the period prior to disposal on 23 April 2002, of 10% of pensionable salaries, plus employer augmentation costs, was based on the advice of the Scheme’s independent qualified actuary and was calculated using the same assumptions as at the last formal actuarial valuation of the Scheme.
The actual contributions payable by participating employers for the period were 10% of pensionable salaries, except where required by a business transfer agreement.
Following the sale of Southern Water on 23 April 2002, the sponsorship of the Southern Water Scheme passed to First Aqua, with no further payments due by ScottishPower after that date. Therefore there are no consequent liabilities in respect of this Scheme.
The pension charge for the year ended 31 March 2004 was £nil (2003 £0.2 million, 2002 £4.1 million). The employer contribution for the year ended 31 March 2004 was £nil (2003 £0.2 million). The provision as at 31 March 2004 was £nil (2003 £nil).
(e) Final Salary LifePlan
The group operates a funded pension scheme providing defined retirement and death benefits based on final pensionable salary for eligible UK employees of the group. The assets of the LifePlan are held in a separate trustee administered fund. The pension charge for the year, of 11.4% of pensionable salaries, is based on the advice of the LifePlan’s independent qualified actuary, representing the assessed balance of cost of the accruing benefits after allowing for members’ contributions of 5% of pensionable salaries. The same actuarial assumptions have been adopted for both funding and expensing purposes.
The actual contributions payable by participating employers during the year were 11.4% of pensionable salaries, except where required by a business transfer agreement. There are no planned changes to employer contribution requirements.
(f) PacifiCorp
PacifiCorp operates pension plans covering substantially all its employees. Benefits are based on the employee’s years of service and final pensionable salary, adjusted to reflect estimated social security benefits. Pension costs are funded annually by no more than the maximum amount of pension expense which can be deducted for federal income tax purposes. The PacifiCorp pensions figures in these Accounts include the unfunded SERP. The SERP accounts for less than 5% of the PacifiCorp liabilities. PacifiCorp meets the entire cost of accruing benefits under PacifiCorp plans. The assets for the funded Plan are held in a separate fund. For funding and expensing purposes, the Plan assets are valued at market levels, and liabilities costed on financial assumptions in line with market return expectations.
The pension charge for the year is based on the advice of the Plan’s independent qualified actuary and is assessed on the results of the formal actuarial valuation carried out as at 1 January 2003. Equity markets were much lower at the valuation date than at the previous valuation date (1 January 2002) used for the 2002/03 figures. This has led to a significantly higher variation cost for the year ending 31 March 2004. The two other components of the pension charge, namely the regular cost and the interest cost, are broadly similar for the previous year.
The net pension charge is derived from a regular cost of 6.9% of salaries, an interest cost of 2.4% of salaries, and a variation cost of 9.5% of salaries. The variation cost is calculated as the assessed deficit, as adjusted for the balance sheet amount, spread as a fixed percentage of pensionable salaries over 11 years.
The actual contributions payable by participating employers during the year were 11.2% of pensionable earnings. The employer’s planned contributions for 2004/05 are 16.7% of pensionable earnings.
PacifiCorp also provides other post-retirement benefits to certain employees. The group has provided £48.6 million as at 31 March 2004 (2003 £55.0 million) for these benefits. The related charge for the year was £17.0 million (2003 £14.3 million). Further details of these benefits are disclosed in Note 34.
(g) Additional pension arrangements
Until 31 August 2003 the group operated an approved defined contribution pension scheme (Money Purchase LifePlan) for eligible employees. Contributions were paid by the member and employer at fixed rates. The benefits secured at retirement or death reflect each employee’s accumulated fund and the cost of purchasing benefits at that time. The assets of the scheme are held in a separate trustee administered fund, although this is to be wound up with the assets and liabilities due to be transferred into the Final Salary LifePlan. The pension charge for the year represents the defined employer contribution and amounted to £nil (2003 £0.1 million).
The group also operates pension arrangements for senior executives, namely the ScottishPower Executive Top-Up Plan (for benefits which are held within UK Inland Revenue limits) and the Unfunded Unapproved Retirement Benefit Scheme (“UURBS”) for benefits beyond these limits. The UURBS has no invested assets and the group has provided £11.3 million as at 31 March 2004 (2003 £9.5 million) for the benefit promises which will ultimately be paid by the group.
Further details of the group’s pensions arrangements, as required under US GAAP, are disclosed in Note 34.
122 ScottishPower Annual Report and Accounts 2003/04
28 Pensions and other post-retirement benefits continued
(h) Financial Reporting Standard (“FRS”) 17 ‘Retirement benefits’
The pension figures shown above comply with the current pension accounting standard, Statement of Standard Accounting Practice (“SSAP”) 24. However, under the transitional arrangements of the new accounting standard, FRS 17, the group is required to disclose the following information about its pension and other post-retirement benefit schemes and the figures that would have been shown under FRS 17 in the balance sheet as at 31 March 2004, 2003 and 2002.
The major assumptions used by the actuary for both the pensions and other post-retirement benefits arrangements were:
| UK arrangements at 31 March 2004 |
UK arrangements at 31 March 2003 |
UK arrangements at 31 March 2002 |
US arrangements at 31 March 2004 |
US arrangements at 31 March 2003 |
US arrangements at 31 March 2002 | |||||||
| Rate of increase in salaries |
4.3% p.a. | 3.9% p.a. | 4.3% p.a. | 4.0% p.a. | 4.0% p.a. | 4.0% p.a. | ||||||
| Rate of increase in deferred pensions |
2.8% p.a. | 2.4% p.a. | 2.8% p.a. | n/a | n/a | n/a | ||||||
| Rate of increase in pensions in payment |
2.8% p.a. | 2.4% p.a. | 2.8% p.a. | n/a | n/a | n/a | ||||||
| Discount rate |
5.5% p.a. | 5.4% p.a. | 6.0% p.a. | 6.0% p.a. | 6.5% p.a. | 7.5% p.a. | ||||||
| Inflation assumption |
2.8% p.a. | 2.4% p.a. | 2.8% p.a. | 3.0% p.a. | 3.0% p.a. | 4.0% p.a. |
Pensions
The group operates defined benefit and defined contribution pension schemes as described earlier in this Note. Formal actuarial valuations were carried out as described earlier and updated to 31 March 2004 by a qualified independent actuary. Figures are shown separately for the UK and US arrangements.
The assets in the schemes and the expected long-term rates of return were as follows:
| UK pension arrangements Value at 31 March 2004 |
UK pension arrangements Value at 31 March 2003 |
UK pension arrangements Value at 31 March 2002 |
US pension arrangements Value at 31 March 2004 |
US pension arrangements Value at 31 March 2003 |
US pension arrangements Value at 31 March 2002 |
|||||||||||||
| £m |
£m |
£m |
£m |
£m |
£m |
|||||||||||||
| Equities |
1,345.2 | 1,241.4 | 1,882.0 | 221.9 | 204.2 | 293.2 | ||||||||||||
| Bonds |
592.3 | 363.4 | 551.1 | 137.9 | 139.3 | 206.8 | ||||||||||||
| Property |
130.7 | 147.2 | 164.3 | — | — | — | ||||||||||||
| Cash |
17.1 | 21.3 | 26.0 | 0.3 | — | — | ||||||||||||
| Private markets |
— | — | — | 41.9 | 50.0 | 81.9 | ||||||||||||
| Total market value of assets |
2,085.3 | 1,773.3 | 2,623.4 | 402.0 | 393.5 | 581.9 | ||||||||||||
| Present value of schemes’ past service liabilities |
(2,257.3 | ) | (2,102.6 | ) | (2,362.3 | ) | (692.1 | ) | (738.2 | ) | (760.1 | ) | ||||||
| (Deficit)/surplus of schemes’ assets over past service liabilities |
(172.0 | ) | (329.3 | ) | 261.1 | (290.1 | ) | (344.7 | ) | (178.2 | ) | |||||||
| Resulting balance sheet (liability)/asset |
(172.0 | ) | (329.3 | ) | 176.9 | * | (290.1 | ) | (344.7 | ) | (178.2 | ) | ||||||
| Related deferred tax asset/(liability) |
51.6 | 98.8 | (53.1 | ) | 110.2 | 131.0 | 67.7 | |||||||||||
| Net pension (liability)/asset |
(120.4 | ) | (230.5 | ) | 123.8 | (179.9 | ) | (213.7 | ) | (110.5 | ) | |||||||
| * | The balance sheet asset which would have arisen under FRS 17 at 31 March 2002 is lower than the total calculated surplus of schemes’ assets over past service liabilities, due to part of the ScottishPower Pension Scheme’s past service ‘surplus’ being designated as ‘non-recoverable’ in FRS 17 terms and therefore excluded from the Balance Sheet. |
The UK pension arrangements net pension (liability)/asset comprises assets (net of deferred tax) of £0.5 million (2003 £nil, 2002 £159.1 million) and liabilities (net of deferred tax) of £120.9 million (2003 £230.5 million, 2002 £35.3 million).
| UK pension arrangements Long-term rates of return expected at 31 March 2004 |
UK pension arrangements Long-term rates of return expected at 31 March 2003 |
UK pension arrangements Long-term rates of return expected at 31 March 2002 |
US pension arrangements Long-term rates of return expected at 31 March 2004 |
US pension arrangements Long-term rates of return expected at 31 March 2003 |
US pension arrangements Long-term rates of return expected at 31 March 2002 | |||||||
| Equities |
7.45% p.a. | 7.2% p.a. | 8.0% p.a. | 9.25% p.a. | 9.25% p.a. | 9.75% p.a. | ||||||
| Bonds |
4.80% p.a. | 4.5% p.a. | 5.3% p.a. | 6.5% p.a. | 6.5% p.a. | 6.5% p.a. | ||||||
| Property |
6.45% p.a. | 6.2% p.a. | 7.0% p.a. | n/a | n/a | n/a | ||||||
| Cash |
3.70% p.a. | 3.45% p.a. | 3.8% p.a. | 4.0% p.a. | n/a | n/a | ||||||
| Private markets |
n/a | n/a | n/a | 14.0% p.a. | 14.0% p.a. | 14.5% p.a. |
For the UK pension arrangements, the long-term rates of return have been derived as follows:
Equities: the long-term UK Government fixed interest stock yield, plus 3% p.a.
Bonds: an appropriate weighted average of long-term UK Government and UK corporate bond yields reflecting the actual split of holdings.
Property: the long-term equities rate of return less 1% p.a.
Cash: the current UK base rate of interest.
In all cases, for FRS17 reporting purposes the long-term rates of return have been reduced by 0.3% p.a. (2003 0.3% p.a.) to reflect scheme expenses to arrive at the figures shown above.
For the US pension and other post-retirement healthcare arrangements, the long-term rates of return have been derived as follows:
Equities: An expected real return of 6.25% plus 3% long-term inflation.
Bonds: An expected real return of 3.50% plus 3% long-term inflation.
Cash: An expected real return of 1% plus 3% long-term inflation.
Private markets: An expected real return of 11% plus 3% long-term inflation.
These return assumptions are based on both historical performance and independent advisors’ forward-looking views of the financial markets.
ScottishPower Annual Report and Accounts 2003/04 123
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
28 Pensions and other post-retirement benefits continued
| UK pension arrangements Year to 31 March 2004 |
US pension arrangements Year to 31 March 2004 |
UK pension arrangements Year to 31 March 2003 |
US pension arrangements Year to 31 March 2003 |
||||||||||||
| Note |
£m |
£m |
£m |
£m |
|||||||||||
| Analysis of the amount charged to operating profit |
|||||||||||||||
| Current service cost |
28.5 | 15.8 | 31.2 | 13.9 | |||||||||||
| Special termination benefits |
— | — | — | (2.5 | ) | ||||||||||
| Total operating profit charge |
(i | ) | 28.5 | 15.8 | 31.2 | 11.4 | |||||||||
| UK pension arrangements Year to 31 March 2004 |
US pension arrangements Year to 31 March 2004 |
UK pension arrangements Year to 31 March 2003 |
US pension arrangements Year to 31 March 2003 |
||||||||||||
| Note |
£m |
£m |
£m |
£m |
|||||||||||
| Analysis of amount credited/(charged) to other finance income |
|||||||||||||||
| Expected return on pension scheme assets |
113.1 | 30.7 | 168.4 | 46.5 | |||||||||||
| Interest on pension liabilities |
(112.3 | ) | (43.0 | ) | (120.6 | ) | (49.6 | ) | |||||||
| Net return on assets/(interest cost) |
(i | ) | 0.8 | (12.3 | ) | 47.8 | (3.1 | ) | |||||||
| (i) The amounts above are stated before capitalisation. |
|||||||||||||||
| UK pension arrangements Year to 31 March 2004 |
US pension arrangements Year to 31 March 2004 |
UK pension arrangements Year to 31 March 2003 |
US pension arrangements Year to 31 March 2003 |
||||||||||||
| £m |
£m |
£m |
£m |
||||||||||||
| Analysis of amount recognised in statement of total recognised gains and losses (“STRGL”) |
|||||||||||||||
| Actual return less expected return on assets |
280.6 | 73.1 | (647.2 | ) | (96.5 | ) | |||||||||
| Experience gains and losses on liabilities |
(17.6 | ) | (16.7 | ) | 68.4 | 6.0 | |||||||||
| Changes in assumptions |
(101.3 | ) | (46.2 | ) | (76.4 | ) | (106.1 | ) | |||||||
| Actuarial gain/(loss) recognised in STRGL |
161.7 | 10.2 | (655.2 | ) | (196.6 | ) | |||||||||
| Adjustment due to surplus cap |
— | — | 84.2 | — | |||||||||||
| Net gain/(loss) recognised |
161.7 | 10.2 | (571.0 | ) | (196.6 | ) | |||||||||
| UK pension arrangements Year to 31 March 2004 |
US pension arrangements Year to 31 March 2004 |
UK pension arrangements Year to 31 March 2003 |
US pension arrangements Year to 31 March 2003 |
||||||||||||
| £m |
£m |
£m |
£m |
||||||||||||
| Movement in (deficit)/surplus in pension schemes during the year |
|||||||||||||||
| (Deficit)/surplus in pension schemes at beginning of year |
(329.3 | ) | (344.7 | ) | 261.1 | (178.2 | ) | ||||||||
| Movement in year: |
|||||||||||||||
| Current service cost |
(28.5 | ) | (15.8 | ) | (31.2 | ) | (13.9 | ) | |||||||
| Gain on settlement/curtailment/special termination |
— | — | 39.4 | 2.5 | |||||||||||
| Contributions |
23.3 | 23.0 | 8.8 | 21.5 | |||||||||||
| Net return on assets/(interest cost) |
0.8 | (12.3 | ) | 47.8 | (3.1 | ) | |||||||||
| Actuarial gain/(loss) |
161.7 | 10.2 | (655.2 | ) | (196.6 | ) | |||||||||
| Exchange |
— | 49.5 | — | 23.1 | |||||||||||
| Deficit in pension schemes at end of year |
(172.0 | ) | (290.1 | ) | (329.3 | ) | (344.7 | ) | |||||||
Other post-retirement benefits
PacifiCorp provides post-retirement healthcare and life insurance benefits as described in Note 34(e). Actuarial valuations were carried out as at 31 March 2004 by a qualified independent actuary. The major assumptions used by the actuary are described in Note 34(e).
The assets in the schemes and the expected long-term rates of return were as follows:
| Value at 31 March 2004 |
Value at 31 March 2003 |
Value at 31 March 2002 |
|||||||
| £m |
£m |
£m |
|||||||
| Equities |
98.4 | 88.6 | 113.0 | ||||||
| Bonds |
55.5 | 52.4 | 67.3 | ||||||
| Private markets |
3.2 | 3.7 | 4.6 | ||||||
| Total market value of assets |
157.1 | 144.7 | 184.9 | ||||||
| Present value of schemes’ liabilities |
(312.1 | ) | (341.4 | ) | (331.3 | ) | |||
| Deficit in the schemes |
(155.0 | ) | (196.7 | ) | (146.4 | ) | |||
| Related deferred tax asset |
58.9 | 74.7 | 55.6 | ||||||
| Net other post-retirement benefits liability |
(96.1 | ) | (122.0 | ) | (90.8 | ) | |||
| Long-term rates of return expected at 31 March 2004 |
Long-term rates of return expected at 31 March 2003 |
Long-term rates of return expected at 31 March 2002 | ||||
| Equities |
9.25% p.a. | 9.25% p.a. | 9.75% p.a. | |||
| Bonds |
6.5% p.a. | 6.5% p.a. | 6.5% p.a. | |||
| Private markets |
14.0% p.a. | 14.0% p.a. | 14.5% p.a. | |||
124 ScottishPower Annual Report and Accounts 2003/04
28 Pensions and other post-retirement benefits continued
| Other post- retirement benefits Year to 31 March 2004 |
Other post- retirement benefits Year to 31 March 2003 |
||||||||
| Note |
£m |
£m |
|||||||
| Analysis of the amount charged to operating profit |
|||||||||
| Current service cost |
4.6 | 3.6 | |||||||
| Adjustment to special termination benefits |
— | (0.6 | ) | ||||||
| Total operating profit charge |
(i | ) | 4.6 | 3.0 | |||||
| Other post- retirement benefits Year to 31 March 2004 |
Other post- retirement benefits Year to 31 March 2003 |
||||||||
| Note |
£m |
£m |
|||||||
| Analysis of amount charged to other finance income |
|||||||||
| Expected return on other post-retirement benefits scheme’s assets |
11.0 | 14.9 | |||||||
| Interest on other post-retirement benefits scheme’s liabilities |
(20.1 | ) | (22.1 | ) | |||||
| Net interest cost |
(i | ) | (9.1 | ) | (7.2 | ) | |||
| (i) The amounts above are stated before capitalisation. |
|||||||||
| Other post- retirement benefits Year to 31 March 2004 |
Other post- retirement benefits Year to 31 March 2003 |
||||||||
| £m |
£m |
||||||||
| Analysis of amount recognised in statement of total recognised gains and losses (“STRGL”) |
|||||||||
| Actual return less expected return on assets |
26.3 | (31.0 | ) | ||||||
| Experience gains and losses on liabilities |
5.3 | (2.9 | ) | ||||||
| Changes in assumptions |
(19.0 | ) | (39.1 | ) | |||||
| Actuarial gain/(loss) recognised in STRGL |
12.6 | (73.0 | ) | ||||||
| Other post- retirement benefits Year to 31 March 2004 |
Other post- retirement benefits Year to 31 March 2003 |
||||||||
| £m |
£m |
||||||||
| Movement in deficit during the year |
|||||||||
| Deficit in schemes at beginning of year |
(196.7 | ) | (146.4 | ) | |||||
| Movement in year: |
|||||||||
| Current service cost |
(4.6 | ) | (3.6 | ) | |||||
| Adjustment to special termination benefits |
— | 0.6 | |||||||
| Contributions |
15.2 | 16.0 | |||||||
| Net interest cost |
(9.1 | ) | (7.2 | ) | |||||
| Actuarial gain/(loss) |
12.6 | (73.0 | ) | ||||||
| Exchange |
27.6 | 16.9 | |||||||
| Deficit in schemes at end of year |
(155.0 | ) | (196.7 | ) | |||||
| Year to 31 March 2004 | Year to 31 March 2003 | |||||||||||||||||
| UK pension schemes |
US pension schemes |
Other post- retirement benefits |
UK pension schemes |
US pension schemes |
Other post- retirement benefits |
|||||||||||||
| £m |
£m |
£m |
£m |
£m |
£m |
|||||||||||||
| History of experience gains and losses |
||||||||||||||||||
| Difference between actual and expected return on scheme assets: |
||||||||||||||||||
| Amount |
280.6 | 73.1 | 26.3 | (647.2 | ) | (96.5 | ) | (31.0 | ) | |||||||||
| Percentage of scheme’s assets |
13 | % | 18 | % | 17 | % | (36 | )% | (24 | )% | (21 | )% | ||||||
| Experience gains and losses on scheme liabilities: |
||||||||||||||||||
| Amount |
(17.6 | ) | (16.7 | ) | 5.3 | 68.4 | 6.0 | (2.9 | ) | |||||||||
| Percentage of scheme’s liabilities |
(1 | )% | (2 | )% | 2 | % | 3 | % | 1 | % | (1 | )% | ||||||
| Total amount recognised in statement of total recognised gains and losses: |
||||||||||||||||||
| Amount |
161.7 | 10.2 | 12.6 | (571.0 | ) | (196.6 | ) | (73.0 | ) | |||||||||
| Percentage of scheme’s liabilities |
7 | % | 1 | % | 4 | % | (27 | )% | (27 | )% | (21 | )% | ||||||
ScottishPower Annual Report and Accounts 2003/04 125
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
28 Pensions and other post-retirement benefits continued
Summary
If the above FRS 17 pensions and other post-retirement benefits assets and liabilities (net of deferred tax) were recognised in the balance sheet as at 31 March 2004 and 31 March 2003, the group’s net assets and profit and loss reserve would be as follows:
| At 31 March 2004 |
At 31 March 2003 (As restated - Note 17) |
|||||
| £m |
£m |
|||||
| Net assets |
4,751.8 | 4,628.8 | ||||
| Reversal of SSAP 24 net pensions/other post-retirement benefits liability (net of deferred tax) |
95.6 | 94.0 | ||||
| Reversal of capitalisation of SSAP 24 costs of pensions/other post-retirement benefits (net of deferred tax) |
(22.9 | ) | (8.0 | ) | ||
| Net assets excluding effect of FRS 17 |
4,824.5 | 4,714.8 | ||||
| Capitalisation of FRS 17 costs of pensions/other post-retirement benefits (net of deferred tax) |
12.5 | 1.5 | ||||
| Net assets excluding FRS 17 pensions/other post-retirement benefits assets and liabilities (net of deferred tax) |
4,837.0 | 4,716.3 | ||||
| FRS 17 pensions assets (net of deferred tax) |
0.5 | – | ||||
| FRS 17 pensions/other post-retirement benefits liabilities (net of deferred tax) |
(396.9 | ) | (566.2 | ) | ||
| Net assets including FRS 17 pensions/other post-retirement benefits liabilities (net of deferred tax) |
4,440.6 | 4,150.1 | ||||
| Profit and loss reserve |
1,019.1 | 894.3 | ||||
| Reversal of SSAP 24 net pensions/other post-retirement benefits liability (net of deferred tax) |
95.6 | 94.0 | ||||
| Reversal of capitalisation of SSAP 24 costs of pensions/other post-retirement benefits (net of deferred tax) |
(22.9 | ) | (8.0 | ) | ||
| Profit and loss reserve excluding effect of FRS 17 |
1,091.8 | 980.3 | ||||
| Capitalisation of FRS 17 costs of pensions/other post-retirement benefits (net of deferred tax) |
12.5 | 1.5 | ||||
| Profit and loss reserve excluding FRS 17 pensions/other post-retirement benefits assets and liabilities (net of deferred tax) |
1,104.3 | 981.8 | ||||
| FRS 17 pensions/other post-retirement benefits assets and liabilities (net of deferred tax) |
(396.4 | ) | (566.2 | ) | ||
| Profit and loss reserve including FRS 17 pensions/other post-retirement benefits assets and liabilities (net of deferred tax) |
707.9 | 415.6 | ||||
29 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 and certain of the Klamath Tribes’ members. 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. The claim seeks in excess of $1.0 billion in damages. PacifiCorp believes it has a number of defences and intends to vigorously defend any claim of liability for the matters alleged by the Klamath Tribes.
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.
30 Financial commitments
(a) Analysis of annual commitments under operating leases
| 2004 | 2003 | |||
| £m |
£m | |||
| Leases of land and buildings expiring: |
||||
| Within one year |
0.7 | 0.4 | ||
| Between one and two years |
1.3 | 0.3 | ||
| Between two and three years |
1.0 | 1.4 | ||
| Between three and four years |
0.6 | 0.8 | ||
| Between four and five years |
0.3 | 0.1 | ||
| More than five years |
3.4 | 2.5 | ||
| 7.3 | 5.5 | |||
| Other operating leases expiring: |
||||
| Within one year |
1.0 | 1.1 | ||
| Between one and two years |
2.4 | 1.9 | ||
| Between two and three years |
1.5 | 2.4 | ||
| Between three and four years |
– | – | ||
| Between four and five years |
– | – | ||
| More than five years |
– | – | ||
| 4.9 | 5.4 | |||
126 ScottishPower Annual Report and Accounts 2003/04
30 Financial commitments continued
(b) Capital commitments
| 2004 | 2003 | |||
| £m |
£m | |||
| Contracted but not provided |
105.8 | 127.4 | ||
(c) Other contractual commitments
| (i) | UK contractual commitments |
Long-term wholesale power, gas and coal contracts
In the UK, ScottishPower manages its energy resource requirements by integrating long-term firm, short-term and spot market purchases with its own generating resources to manage volume and price volatility and maximise value across the energy value chain. As part of its UK energy resource portfolio, ScottishPower is committed under long-term purchase contracts to purchases of £1,180.7 million, £460.0 million, £223.3 million, £163.3 million and £103.2 million for the years 2005 to 2009 respectively and £245.3 million thereafter.
| (ii) | PacifiCorp contractual commitments |
Long-term wholesale sales and purchased power contracts
In the US, PacifiCorp manages its energy resource requirements by integrating long-term firm, short-term and spot market purchases with its own generating resources to economically operate the system (within the boundaries of Federal Energy Regulatory Commission requirements) and meet commitments for wholesale sales and retail load growth. The long-term wholesale sales commitments include contracts with minimum sales requirements of £145.1 million, £122.5 million, £102.3 million, £82.0 million and £74.2 million for the years 2005 to 2009 respectively and £0.5 billion thereafter. As part of its energy resource portfolio, PacifiCorp acquires a portion of its power through long-term purchases and/or exchange agreements which require minimum fixed payments of £232.2 million, £237.5 million, £217.7 million, £156.1 million and £140.5 million for the years 2005 to 2009 respectively, and £1.4 billion thereafter.
Excluded from the minimum fixed annual payments above are commitments to purchase power from several hydroelectric projects under long-term arrangements with public utility districts. These purchases are made on a ‘cost-of-service’ basis for a stated percentage of project output and for a like percentage of project annual costs (operating expenses and debt service). PacifiCorp is required to pay its portion of operating expenses and its portion of the debt service, whether or not any power is produced. The arrangements provide for non-withdrawable power and the majority also provide for additional power, withdrawable by the public utility districts upon one to five years’ notice. For 2004, these purchases represented approximately 2.3% of PacifiCorp’s energy requirements. At 31 March 2004, PacifiCorp’s share of long-term arrangements with public utility districts were as follows:
| Generating facility |
Year contract expires |
Percentage of output |
Capacity (kW) |
Annual costs* | |||||
| £m | |||||||||
| Wanapum |
2009 | 18.7 | % | 155,444 | 3.9 | ||||
| Priest Rapids |
2005 | 13.9 | % | 109,602 | 2.4 | ||||
| Rocky Reach |
2011 | 5.3 | % | 64,297 | 2.2 | ||||
| Wells |
2018 | 6.9 | % | 59,617 | 1.3 | ||||
| Total |
388,960 | 9.8 | |||||||
| * | The annual costs include debt service costs of £3.8 million. PacifiCorp’s minimum debt service obligation at 31 March 2004 was £3.3 million and for the years 2005 to 2009 are £3.5 million, £4.4 million, £6.1 million, £6.0 million and £6.6 million respectively. |
Short-term wholesale sales and purchased power contracts
At 31 March 2004, PacifiCorp had short-term wholesale forward sales commitments that included contracts with minimum sales requirements of £197.3 million, £91.6 million and £24.7 million for the years 2005 to 2007 respectively. At 31 March 2004, short-term forward purchase agreements require minimum fixed payments of £152.0 million, £46.8 million and £8.3 million for the years 2005 to 2007 respectively.
Fuel contracts
PacifiCorp has ‘take or pay’ coal and natural gas contracts that require minimum fixed payments of £139.0 million, £196.0 million, £93.5 million, £88.8 million and £74.6 million for the years 2005 to 2009 respectively and £428.3 million thereafter.
| (iii) | PPM contractual commitments |
At 31 March 2004, PPM had purchase commitments of £475.3 million of which £251.1 million relates to the years 2005 to 2009. PPM’s contractual commitments primarily consist of electricity and gas purchases made to optimise returns from generation resources and commercial activities.
ScottishPower Annual Report and Accounts 2003/04 127
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
31 Related party transactions
(a) Trading transactions and balances arising in the normal course of business
| Sales/(purchases) to/(from) other group companies during the year |
Amounts due from/(to) other group companies |
||||||||||||||||
| 2004 | 2003 | 2002 | 2004 | 2003 | |||||||||||||
| Related party |
Related party relationship to group |
£m |
£m |
£m |
£m |
£m |
|||||||||||
| Sales by related parties |
|||||||||||||||||
| Scottish Electricity Settlements Limited |
50% owned joint venture |
4.7 | 5.0 | 5.3 | 1.0 | 1.1 | |||||||||||
| ScotAsh Limited |
50% owned joint venture |
1.1 | 0.6 | 0.6 | 0.1 | 0.2 | |||||||||||
| South Coast Power Limited |
50% owned joint venture |
111.3 | 74.2 | 46.5 | 13.6 | 9.3 | |||||||||||
| CeltPower Limited |
50% owned joint venture |
3.7 | 2.0 | 1.7 | 0.9 | 0.3 | |||||||||||
| Thus* |
Subsidiary |
– | – | 0.9 | – | – | |||||||||||
| Purchases by related parties |
|||||||||||||||||
| Scottish Electricity Settlements Limited |
50% owned joint venture |
(0.2 | ) | (0.2 | ) | (0.2 | ) | – | – | ||||||||
| ScotAsh Limited |
50% owned joint venture |
(0.2 | ) | (0.2 | ) | (0.2 | ) | – | – | ||||||||
| South Coast Power Limited |
50% owned joint venture |
(60.7 | ) | (35.3 | ) | (7.8 | ) | (8.1 | ) | (4.1 | ) | ||||||
| Klamath co-generation plant |
Joint arrangement |
(32.9 | ) | (24.8 | ) | (24.1 | ) | (2.0 | ) | (5.0 | ) | ||||||
| CeltPower Limited |
50% owned joint venture |
– | – | (0.3 | ) | – | – | ||||||||||
| Thus* |
Subsidiary |
– | – | (0.1 | ) | – | – | ||||||||||
| N.E.S.T. Makers Limited |
50% owned joint venture |
– | (1.6 | ) | (0.3 | ) | – | – | |||||||||
| Southern Water** |
Subsidiary |
– | (2.7 | ) | – | – | (0.2 | ) | |||||||||
During the year ended 31 March 2004, ScottishPower made management and similar charges to ScotAsh Limited of £0.4 million (2003 £0.1 million, 2002 £0.4 million).
During the year ended 31 March 2004, ScottishPower Energy Retail Limited acquired customers from N.E.S.T. Makers Limited for £2.8 million (2003 £nil, 2002 £nil).
| * | On 19 March 2002 the group demerged Thus. The related party sales and purchases in 2002 represent those transactions between ScottishPower and Thus for the period from 20 March to 31 March 2002. |
| ** | On 23 April 2002, the group disposed of Southern Water; as a result it ceased to be a subsidiary from this date. The sales and purchases for 2003 represent those transactions between ScottishPower and Southern Water for the period from 24 April 2002 to 31 March 2003. |
(b) Funding transactions and balances arising in the normal course of business
| Interest payable to other group companies during the year |
Amounts due to other group companies as at 31 March |
|||||||||||||
| 2004 | 2003 | 2004 | 2003 | |||||||||||
| Related party |
Related party relationship to group |
£m |
£m |
£m |
£m |
|||||||||
| Scottish Electricity Settlements Limited |
50% owned joint venture |
(0.7 | ) | (0.8 | ) | (10.1 | ) | (12.2 | ) | |||||
| ScotAsh Limited |
50% owned joint venture |
– | – | (3.4 | ) | (3.7 | ) | |||||||
| South Coast Power Limited |
50% owned joint venture |
(1.3 | ) | (1.2 | ) | (19.1 | ) | (18.2 | ) | |||||
| RoboScot (38) Limited |
50% owned joint venture |
– | – | (5.4 | ) | (5.4 | ) | |||||||
| N.E.S.T. Makers Limited |
50% owned joint venture |
– | – | (0.6 | ) | (0.7 | ) | |||||||
| Colorado Wind Ventures LLC |
50% owned joint venture |
– | – | (0.2 | ) | – | ||||||||
128 ScottishPower Annual Report and Accounts 2003/04
32 Southern Water disposal
On 23 April 2002, the group completed the sale of Aspen 4 Limited (the holding company of Southern Water plc) to First Aqua Limited for a total consideration, before expenses, of £2.05 billion including repayment and acquisition of intra-group non-trading indebtedness and assumption by First Aqua Limited of Southern Water’s non-trading debt due to third parties. The net assets disposed of were as follows:
| Notes |
£m |
|||||
| Tangible fixed assets |
16, (i | ) | 2,474.7 | |||
| Fixed asset investments |
17 | 1.9 | ||||
| Current assets |
193.1 | |||||
| Creditors: amounts falling due within one year |
||||||
| – Loans and other borrowings: |
||||||
| – Inter-company loan |
(756.4 | ) | ||||
| – Bank overdraft |
(6.2 | ) | ||||
| – Other creditors |
(291.2 | ) | ||||
| Creditors: amounts falling due after more than one year |
||||||
| – Loans and other borrowings |
(100.0 | ) | ||||
| Provisions for liabilities and charges |
||||||
| – Deferred tax |
22 | (361.0 | ) | |||
| – Other provisions |
23 | (5.6 | ) | |||
| Deferred income |
24 | (37.4 | ) | |||
| Book value of Southern Water net assets disposed |
1,111.9 | |||||
| Gain on disposal |
(i | ) | – | |||
| Net disposal proceeds |
1,111.9 | |||||
| Satisfied by: |
||||||
| Cash received for net assets |
(ii | ) | 1,187.3 | |||
| Cash expenses |
(47.9 | ) | ||||
| Net disposal cash proceeds |
1,139.4 | |||||
| Accrued expenses |
(27.5 | ) | ||||
| Net disposal proceeds |
1,111.9 | |||||
| (i) | In the year ended 31 March 2002, an exceptional impairment provision of £449.3 million was made to reduce the carrying value of Southern Water’s net assets to their recoverable amount. In addition, a further exceptional charge of £738.2 million was recognised representing the impairment of goodwill on the acquisition of Southern Water previously written off to reserves. As a consequence of these charges to profits in the year ended 31 March 2002, there was no further gain or loss required to be recognised for the year ended 31 March 2003 on completion of the sale. |
| (ii) | Analysis of total consideration before expenses |
| £m | ||
| Cash received for net assets |
1,187.3 | |
| Cash received on repayment to ScottishPower of inter-company loan |
756.4 | |
| Cash consideration before expenses |
1,943.7 | |
| Debt due to third parties assumed by First Aqua Limited (including premium of £6.3 million) |
106.3 | |
| Total consideration before expenses |
2,050.0 | |
33 Thus Group plc demerger
On 19 March 2002, the group demerged Thus Group plc (“Thus”). The demerger of Thus was preceded by an open offer of approximately £275 million of new equity shares in Thus which resulted in ScottishPower’s equity interest in Thus temporarily increasing from 50.1% to 72.4%, and an increase in goodwill of £34.4 million. Thus’ results for the period to 19 March 2002 were reported under discontinued operations in the ScottishPower Accounts for the year ended 31 March 2002. The demerger of Thus was accounted for as a dividend in specie.
| Notes |
£m |
||||
| Intangible fixed assets – goodwill |
62.6 | ||||
| Tangible fixed assets |
468.8 | ||||
| Fixed assets investments |
24.2 | ||||
| Current assets |
104.5 | ||||
| Creditors: amounts falling due within one year |
(109.9 | ) | |||
| Provisions for liabilities and charges |
|||||
| – Other provisions |
23 | (0.9 | ) | ||
| Book value of Thus net assets disposed |
549.3 | ||||
| Minority interest share of net assets |
(127.4 | ) | |||
| ScottishPower’s share of Thus net assets disposed |
421.9 | ||||
| Goodwill previously charged to reserves written back |
26 | 14.7 | |||
| Dividend in specie |
436.6 | ||||
ScottishPower Annual Report and Accounts 2003/04 129
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
34 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’)
The consolidated Accounts of the group are prepared in accordance with UK GAAP which differs in certain significant respects from US GAAP. The effect of the US GAAP adjustments to profit/(loss) for the financial year and equity shareholders’ funds are set out in the tables below.
| Year ended 31 March | |||||||||||
| 2004 | 2003 | 2002 | |||||||||
| (a) Reconciliation of profit/(loss) for the financial year to US GAAP: | Notes |
£m |
£m |
£m |
|||||||
| Profit/(loss) for the financial year under UK GAAP |
537.9 | 482.6 | (987.1 | ) | |||||||
| US GAAP adjustments: |
|||||||||||
| Amortisation of goodwill |
(i) | 128.0 | 139.0 | (23.5 | ) | ||||||
| Disposal of businesses |
(ii) | – | – | 279.1 | |||||||
| US regulatory net assets |
(iii) | (81.2 | ) | (121.6 | ) | 95.3 | |||||
| Pensions |
(iv) | (0.1 | ) | 20.1 | 40.0 | ||||||
| Impairment on demerger of Thus |
(v) | – | – | (243.7 | ) | ||||||
| Depreciation on revaluation uplift |
(vi) | 1.9 | 2.0 | 3.4 | |||||||
| Decommissioning and mine reclamation liabilities |
(vii) | (13.0 | ) | (38.3 | ) | (21.8 | ) | ||||
| PacifiCorp Transition Plan costs |
(viii) | (29.0 | ) | (19.1 | ) | (29.9 | ) | ||||
| Business combinations |
(i) | – | (31.6 | ) | – | ||||||
| FAS 133 |
(ix) | 153.3 | 205.5 | 144.5 | |||||||
| Other |
(xiv) | (10.3 | ) | (10.8 | ) | (17.7 | ) | ||||
| 687.5 | 627.8 | (761.4 | ) | ||||||||
| Deferred tax effect of US GAAP adjustments |
(x) | 54.7 | 20.4 | (64.0 | ) | ||||||
| Profit/(loss) for the financial year under US GAAP before cumulative adjustment for FAS 143 (2003 C15 and C16, 2002 FAS 133) |
742.2 | 648.2 | (825.4 | ) | |||||||
| Cumulative adjustment for FAS 143 (2003 C15 and C16, 2002 FAS 133) |
(vii), (ix) | (0.6 | ) | 141.1 | (61.6 | ) | |||||
| Profit/(loss) for the financial year under US GAAP |
741.6 | 789.3 | (887.0 | ) | |||||||
| Earnings/(loss) per share under US GAAP |
(xii) | 40.54p | 42.81p | (48.26 | )p | ||||||
| Diluted earnings/(loss) per share under US GAAP |
(xii) | 39.19p | 42.70p | (48.26 | )p | ||||||
| 31 March 2004 |
31 March 2003 (As restated – Note 17) |
||||||||
| (b) Effect on equity shareholders’ funds of differences between UK GAAP and US GAAP: | Notes |
£m |
£m |
||||||
| Equity shareholders’ funds under UK GAAP |
4,690.9 | 4,554.9 | |||||||
| US GAAP adjustments: |
|||||||||
| Goodwill |
(i | ) | 572.3 | 572.3 | |||||
| Business combinations |
(i | ) | (196.1 | ) | (226.3 | ) | |||
| Amortisation of goodwill |
(i | ) | 150.0 | 51.0 | |||||
| US regulatory net assets |
(iii | ) | 724.7 | 1,007.9 | |||||
| Pensions |
(iv | ) | (18.9 | ) | (412.8 | ) | |||
| Cash dividends |
(xi | ) | 112.9 | 132.2 | |||||
| Revaluation of fixed assets |
(vi | ) | (54.0 | ) | (54.0 | ) | |||
| Depreciation on revaluation uplift |
(vi | ) | 12.4 | 10.5 | |||||
| Decommissioning and mine reclamation liabilities |
(vii | ) | (14.9 | ) | 0.4 | ||||
| PacifiCorp Transition Plan costs |
(viii | ) | 22.2 | 56.1 | |||||
| FAS 133 |
(ix | ) | 2.2 | (66.8 | ) | ||||
| ESOP shares held in trust |
(xiii | ) | – | 45.2 | |||||
| Other |
(xiv | ) | (12.9 | ) | (12.1 | ) | |||
| Deferred tax: |
|||||||||
| Effect of US GAAP adjustments |
(x | ) | (275.0 | ) | (157.4 | ) | |||
| Effect of differences in methodology |
(x | ) | 14.5 | (21.4 | ) | ||||
| Equity shareholders’ funds under US GAAP |
5,730.3 | 5,479.7 | |||||||
(i) Goodwill and business combinations
Goodwill
Under UK GAAP, goodwill arising from the purchase of operating entities before 31 March 1998 has been written off directly to reserves. Additionally, UK GAAP requires that on subsequent disposal of these entities any goodwill previously taken directly to reserves is then charged in the profit and loss account against the profit or loss on disposal. Goodwill arising on acquisitions after 31 March 1998 is capitalised and amortised through the profit and loss account over its useful economic life.
The goodwill adjustment is made to recognise goodwill previously written off to reserves under UK GAAP as an intangible asset under US GAAP.
Under US GAAP, following the introduction of Statement of Financial Accounting Standard No. 142 ‘Goodwill and Other Intangible Assets’ (“FAS 142”) which was effective for the group from 1 April 2002, goodwill arising from the purchase of operating entities should be held as an indefinite lived intangible asset in the balance sheet and is no longer amortised. Instead goodwill is subject to an impairment test performed at least annually. The adjustment ‘Amortisation of goodwill’ for the years ended 31 March 2004 and 31 March 2003 represents the reversal of amortisation of goodwill charged under UK GAAP. The impact of reporting under FAS 142 for the year ended 31 March 2002 would have been to reduce the loss under US GAAP by £172.5 million to £714.5 million and to reduce the loss per share under US GAAP by 9.38 pence per share to 38.88 pence per share.
The group has completed its annual goodwill impairment analysis under FAS 142 as at 30 September 2003 and has concluded that goodwill is not impaired. The following table provides an analysis of goodwill included in the balance sheet under US GAAP for the years ended 31 March 2004 and 31 March 2003.
130 ScottishPower Annual Report and Accounts 2003/04
34 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’) continued
| 2004 | 2003 | ||||||||
| Notes |
£m |
£m |
|||||||
| Net book value of goodwill capitalised under US GAAP: |
|||||||||
| At 1 April |
2,677.6 | 2,937.7 | |||||||
| Acquisition |
— | 12.4 | |||||||
| Business combinations |
(i | ) | — | (36.7 | ) | ||||
| Exchange |
(295.5 | ) | (235.8 | ) | |||||
| As at 31 March |
(ii | ) | 2,382.1 | 2,677.6 | |||||
| (i) | The Business combinations adjustment of £36.7 million related to deferred tax provisions recognised on the acquisition of PacifiCorp. |
| (ii) | The net book value of goodwill capitalised under US GAAP is analysed by business segment in the table below: |
| 31 March 2004 |
31 March 2003 | ||||||
| Notes |
£m |
£m | |||||
| UK Division – Integrated Generation and Supply |
562.9 | 562.9 | |||||
| PacifiCorp |
(i | ) | 1,808.5 | 2,102.3 | |||
| PPM |
(i | ) | 10.7 | 12.4 | |||
| United States total |
1,819.2 | 2,114.7 | |||||
| Total |
2,382.1 | 2,677.6 | |||||
| (i) | Year-on-year movements on the net book value of goodwill capitalised for PacifiCorp of £293.8 million and PPM of £1.7 million relate solely to foreign exchange. |
Business combinations
In addition to re-instating the goodwill calculated under UK GAAP as described above, goodwill must also be recalculated in accordance with US GAAP. This is required due to differences between UK GAAP and US GAAP in the determination of acquisition price and valuation of assets and liabilities at the acquisition date. The adjustment referred to as Business combinations reflects principally the impact of recalculating the goodwill arising on the acquisitions of Manweb and PacifiCorp under US GAAP. The Business combinations adjustment of £31.6 million (£22.1 million net of tax) reflected in the reconciliation of profit/(loss) to US GAAP for the year ended 31 March 2003 represented the difference between UK GAAP and US GAAP in accounting for accruals recognised under UK GAAP when PacifiCorp was acquired.
In cases where traded equity securities are exchanged as consideration, UK GAAP requires the fair value of consideration to be determined at the date the transaction is completed, while US GAAP requires the fair value of such consideration to be determined at the date the acquisition is announced.
(ii) Disposal of businesses
Under UK GAAP the loss on disposal of and withdrawal from Appliance Retailing and the provision for loss on disposal of Southern Water were calculated based on net asset value, together with the goodwill previously written off to reserves.
Under US GAAP the same methodology was applied, however the net asset value under US GAAP differed from that under UK GAAP. The principal differences relate to the amortisation of goodwill which had been recognised as an intangible asset under US GAAP but had been written off to reserves under UK GAAP and the revaluation of certain tangible fixed assets, which is not permitted under US GAAP but is permitted under UK GAAP.
(iii) US regulatory net assets
FAS 71 ‘Accounting for the Effects of Certain Types of Regulation’ establishes US GAAP for utilities in the US whose regulators have the power to approve and/or regulate rates that may be charged to customers. FAS 71 provides that regulatory assets may be capitalised if it is probable that future revenue in an amount at least equal to the capitalised costs will result from the inclusion of that cost in allowable costs for ratemaking purposes. Due to the different regulatory environment, no equivalent GAAP applies in the UK.
Under UK GAAP, the group’s policy is to recognise regulatory assets established in accordance with FAS 71 only where they comprise rights or other access to future economic benefits which have arisen as a result of past transactions or events which have created an obligation to transfer economic benefits to a third party. Measurement of the past transaction or event and hence the regulatory asset, is determined in accordance with UK GAAP.
The impact of the application of different accounting policies is that US regulatory net assets amounting to £724.7 million (2003 £1,007.9 million) are not recognised under UK GAAP, including deferred excess power costs, certain FAS 133 regulatory balances and certain pension regulatory balances.
Profits under US GAAP are consequently decreased by £81.2 million in 2004 (2003 £121.6 million).
US regulatory net assets relating to the PacifiCorp Transition Plan costs are discussed in note (viii) below.
(iv) Pension costs
The fundamental differences between UK GAAP (as represented by SSAP 24) and US GAAP are as follows:
(a) Under UK GAAP, the annual pension charge is determined so that it is a substantially level percentage of the current and expected future payroll. Under US GAAP, the aim is to accrue the cost of providing pension benefits in the year in which the employee provides the related service in accordance with FAS 87, which requires re-adjustment of the significant actuarial assumptions annually to reflect current market and economic conditions.
(b) Under UK GAAP, pension liabilities are usually discounted using an interest rate that represents the expected long-term return on plan assets. Under US GAAP, pension liabilities are discounted using the current rates at which the pension liability could be settled.
(c) Under UK GAAP, variations from plan can be aggregated and amortised over the remaining employee service lives. Under US GAAP, variations from plan must be amortised separately over remaining service lives.
(d) Under UK GAAP, alternative bases can be used to value plan assets. Under US GAAP, plan assets should be valued at market or at market related values and where the fair/market value of the plan assets is less than the accumulated benefit obligation a minimum pension liability is then recognised as a charge to other comprehensive income under the provisions of FAS 87 unless and to the extent that FAS 71 can be applied in which case a pension regulatory asset is recognised.
ScottishPower Annual Report and Accounts 2003/04 131
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
34 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’) continued
(v) Impairment on demerger of Thus
Under UK GAAP, the demerger dividend was calculated based on the book value of the net assets disposed of as a result of demerger.
Under US GAAP, the demerger dividend was calculated based on the market value of the shares at the demerger date and the difference between this and the book value of net assets disposed of was disclosed as an impairment charge under US GAAP.
(vi) Revaluation of fixed assets
The revaluation of assets is not permitted under US GAAP. The reconciliation therefore adjusts fixed assets to historical cost and the depreciation charge has been adjusted accordingly.
(vii) Decommissioning and mine reclamation liabilities
Under UK GAAP, future decommissioning and mine reclamation costs are provided for on a discounted basis with a corresponding increase to the cost of the asset. This increased cost is depreciated over the useful life of the asset. Under US GAAP, legal obligations associated with decommissioning and mine reclamation costs are accounted for on a similar basis in accordance with FAS 143 ‘Accounting for Asset Retirement Obligations’ (“FAS 143”). Details of the cumulative adjustment arising on the implementation of FAS 143 are given in Note 34(g). For other decommissioning and mine reclamation costs, regulated industries rateably accrue these costs and include them within US regulatory net assets, as the costs are recovered in depreciation rates.
(viii) PacifiCorp Transition Plan costs
Under UK GAAP, PacifiCorp Transition Plan costs were recognised as an expense in the profit and loss account at the date of the announcement of the Plan. Costs were provided for in accordance with FRS 12 ‘Provisions, contingent liabilities and contingent assets’.
Under US GAAP, PacifiCorp Transition Plan costs are accounted for as regulatory assets and are being amortised through the income statement. Costs have been accounted for in accordance with Emerging Issues Task Force No. 94-3 ‘Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)’ and FAS 88 ‘Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits’.
(ix) FAS 133 – derivative instruments and hedging activities
Under UK GAAP derivatives designated as used for non-trading purposes are accounted for on a consistent basis with the asset, liability or position being hedged. Under US GAAP, the group applies FAS 133 ‘Accounting for Derivative Instruments and Hedging Activities’, as amended by FAS 138 ‘Accounting for Certain Derivative Instruments and Certain Hedging Activities’ and FAS 149 ‘Amendment of Statement 133 on Derivative Instruments and Hedging Activities’ and guidance issued by the Derivative Implementation Group. The adjustments in the reconciliations of profit/(loss) and equity shareholders’ funds to US GAAP described as ‘FAS 133’ comprise FAS 133 and subsequent revising standards, FAS 138 and FAS 149, together with guidance issued by the Derivatives Implementation Group. Effective from 1 April 2002, the group adopted revised FAS 133 guidance issued by the Derivatives Implementation Group under Revised Issue C15 ‘Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity’ and Issue C16 ‘Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option Contract’. This new guidance had the effect of including an increased number of the group’s contracts within the scope of FAS 133. The cumulative adjustment to profit under US GAAP for the year ended 31 March 2003 as a result of adopting Revised Issue C15 and Issue C16 was an increase to profit of £228.6 million (£141.1 million, net of tax). FAS 133 requires recognition of all derivatives, as defined in the standard, on the balance sheet at fair value. Derivatives, or any portion thereof, that are not an effective hedge, are adjusted to fair value through income. If a derivative qualifies as an effective hedge, changes in the fair value of the derivative are either offset against the change in fair value of the hedged asset, liability, or firm commitment recognised in income, or are recognised in accumulated other comprehensive income until the hedged items are recognised in earnings. The effects of changes in fair value of certain derivative instruments entered into to hedge future retail resource requirements in the group’s US regulated business are subject to regulation and therefore are deferred pursuant to FAS 71. The FAS 133 adjustment included within equity shareholders’ funds at 31 March 2004 of £2.2 million includes a net liability of £229.7 million which is subject to regulation and is therefore offset by a US regulatory asset of £229.7 million.
Contracts that qualify as normal purchases and normal sales are excluded from the requirements of FAS 133. The realised gains and losses on these contracts are reflected in the income statement at the contract settlement date.
(x) Deferred tax
Under UK GAAP, FRS 19 ‘Deferred tax’, requires full provision for deferred tax at future enacted rates. Provision is only made in respect of assets revalued for accounting purposes where a commitment exists to sell the asset at the balance sheet date.
Under US GAAP, full provision for deferred tax is required to the extent that accounting profit differs from taxable profit due to temporary timing differences. Provision is made based on enacted tax law.
The item ‘Effect of US GAAP adjustments’ reflects the additional impact of making full provision for deferred tax in respect of adjustments made in restating the balance sheet to US GAAP.
The item ‘Effect of differences in methodology’ reflects the impact of making full provision for deferred tax under US GAAP compared to UK GAAP.
Under UK GAAP the group recognised a £48.0 million tax credit through reserves as tax on translation differences on foreign currency hedging as a result of the application of the transitional rules contained in the Finance Act 2002, Schedule 26. Under US GAAP, this £48.0 million tax credit has been recognised within the income statement as required by FAS 109 ‘Accounting for Income Taxes’.
(xi) Cash dividends
Under UK GAAP, final ordinary cash dividends are recognised in the financial year in respect of which they are proposed by the Board of Directors. Under US GAAP, such dividends are not recognised until they are formally declared by the Board of Directors.
132 ScottishPower Annual Report and Accounts 2003/04
34 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’) continued
(xii) Earnings/(loss) per share
Earnings/(loss) per ordinary share have been calculated by dividing the profit/(loss) for the financial year under US GAAP by the weighted average number of ordinary shares in issue during the financial year, based on the following information:
| 2004 |
2003 |
2002 |
|||||||
| Basic earnings/(loss) per share |
|||||||||
| Profit/(loss) for the financial year under US GAAP (£ million) |
741.6 | 789.3 | (887.0 | ) | |||||
| Basic weighted average share capital (number of shares, millions) |
1,829.5 | 1,843.9 | 1,837.8 | ||||||
| Earnings per share under US GAAP – continuing operations |
40.57 | p | 35.76 | p | 19.15 | p | |||
| Loss per share under US GAAP – discontinued operations |
— | (0.60 | )p | (64.06 | )p | ||||
| Earnings/(loss) per share under US GAAP before cumulative adjustment for FAS 143 (2003 C15 and C16, 2002 FAS 133) |
40.57 | p | 35.16 | p | (44.91 | )p | |||
| (Loss)/earnings per share under US GAAP – cumulative adjustment for FAS 143 (2003 C15 and C16, 2002 FAS 133) |
(0.03 | )p | 7.65 | p | (3.35 | )p | |||
| Earnings/(loss) per share under US GAAP |
40.54 | p | 42.81 | p | (48.26 | )p | |||
| Diluted earnings/(loss) per share |
|||||||||
| Profit/(loss) for the financial year under US GAAP (£ million) |
740.7 | 789.3 | (887.0 | ) | |||||
| Diluted weighted average share capital (number of shares, millions) |
1,890.2 | 1,848.4 | 1,840.1 | ||||||
| Diluted earnings per share under US GAAP – continuing operations |
39.22 | p | 35.67 | p | 19.15 | p | |||
| Diluted loss per share under US GAAP – discontinued operations |
— | (0.60 | )p | (64.06 | )p | ||||
| Diluted earnings/(loss) per share under US GAAP before cumulative adjustment for FAS 143 (2003 C15 and C16, 2002 FAS 133) |
39.22 | p | 35.07 | p | (44.91 | )p | |||
| Diluted (loss)/earnings per share under US GAAP – cumulative adjustment for FAS 143 (2003 C15 and C16, 2002 FAS 133) |
(0.03 | )p | 7.63 | p | (3.35 | )p | |||
| Diluted earnings/(loss) per share under US GAAP |
39.19 | p | 42.70 | p | (48.26 | )p | |||
The difference between the basic earnings/(loss) for the financial year under US GAAP and the diluted earnings/(loss) for the financial year under US GAAP is attributable to the interest charged on the convertible bonds of £7.1 million and the mark to market gain on the convertible bonds of £8.0 million. 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. In accordance with FAS 128 ‘Earnings per share’ the diluted loss per share for the year ended 31 March 2002 does not assume the exercise of securities that have an antidilutive effect on the loss per share. The loss per share for March 2003 and 2002 for discontinued operations have been calculated based on US GAAP earnings which are net of £3.0 million and £49.0 million, respectively of interest and similar charges and a tax (credit)/charge of £(4.6) million and £15.2 million, respectively. The group’s charge for interest and similar charges has been allocated between continuing and discontinued operations on the basis of external and internal borrowings of the respective operations.
As permitted under UK GAAP, earnings/(loss) per share have been presented including and excluding the impact of exceptional items and goodwill amortisation to provide an additional measure of underlying performance. UK GAAP permits the presentation of more than one measure of earnings/(loss) per share provided that all such measures are clearly explained and given equal prominence on the face of the profit and loss account. In accordance with US GAAP, earnings/(loss) per share have been presented above based on US GAAP earnings/(loss), without adjustments for the impact of UK GAAP exceptional items and goodwill amortisation. Such additional measures of underlying performance are not permitted under US GAAP.
(xiii) ESOP shares held in trust
In previous years UK GAAP required that shares held by employee share ownership trusts be recorded as fixed asset investments less amounts written off. As a result of the implementation of UITF 38 this treatment has been revised as described in detail in Note 17. Under US GAAP in previous years shares held in trust were recorded as a deduction from shareholders’ funds to the extent that they had no performance conditions attached. The US GAAP adjustment for ESOP shares held under trust is no longer required.
(xiv) Other
Other differences between UK and US GAAP are not individually material and relate to post-retirement benefits other than pensions, capitalisation of finance costs, investment tax credits, available-for-sale securities and stock option compensation expense.
UK GAAP permits the use of long-term discount rates in determining the provision for post-retirement benefits other than pensions. US GAAP requires the use of current market rates. Under UK GAAP, only interest on debt funding may be capitalised during the period of construction. Under US GAAP, as applied by regulated electricity utilities, both the cost of debt and the cost of equity applicable to domestic utility properties are capitalised during the period of construction.
Under US GAAP, investment tax credits for PacifiCorp are deferred and amortised to income over periods prescribed by PacifiCorp’s various regulatory jurisdictions.
Available-for-sale securities
UK GAAP permits fixed asset investments to be valued at cost less provision for any impairment in value. US GAAP requires that such investments, insofar as they are available-for-sale securities, are marked to market with movements in market value being included in other comprehensive income.
The book value and estimated fair value of available-for-sale securities were as follows:
| At 31 March 2004 | |||||||||
| Book value |
Gross unrealised gains |
Gross unrealised losses |
Estimated fair value | ||||||
| £m |
£m |
£m |
£m | ||||||
| Money market account |
1.3 | — | — | 1.3 | |||||
| Mutual fund account |
14.2 | — | (0.2 | ) | 14.0 | ||||
| Debt securities |
10.1 | 0.3 | (1.7 | ) | 8.7 | ||||
| Equity securities |
32.5 | 4.4 | (5.7 | ) | 31.2 | ||||
| Total |
58.1 | 4.7 | (7.6 | ) | 55.2 | ||||
| At 31 March 2003 | |||||||||
| Book value |
Gross unrealised gains |
Gross unrealised losses |
Estimated fair value | ||||||
| £m |
£m |
£m |
£m | ||||||
| Money market account |
2.5 | — | — | 2.5 | |||||
| Mutual fund account |
19.4 | — | (0.2 | ) | 19.2 | ||||
| Debt securities |
10.8 | 0.4 | (1.7 | ) | 9.5 | ||||
| Equity securities |
35.0 | 0.5 | (6.3 | ) | 29.2 | ||||
| Total |
67.7 | 0.9 | (8.2 | ) | 60.4 | ||||
The quoted market price of securities at 31 March is used to estimate the securities’ fair value.
ScottishPower Annual Report and Accounts 2003/04 133
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
34 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’) continued
The book value and estimated fair value of debt securities by contractual maturities at 31 March 2004 and 2003 are shown below. Actual maturities may differ from contractual maturities because borrowers may have the right to call or pre-pay obligations with or without call or prepayment penalties.
| At 31 March 2004 | At 31 March 2003 | ||||||||||
| Book value |
Estimated fair value |
Book value |
Estimated fair value | ||||||||
| Note |
£m |
£m |
£m |
£m | |||||||
| Debt securities |
|||||||||||
| Due within one year |
— | — | 0.5 | 0.5 | |||||||
| Due between one and five years |
1.9 | 1.6 | 1.6 | 1.4 | |||||||
| Due between five and ten years |
4.9 | 4.3 | 4.5 | 4.0 | |||||||
| Due after ten years |
3.3 | 2.8 | 4.2 | 3.6 | |||||||
| Money market account |
1.3 | 1.3 | 2.5 | 2.5 | |||||||
| Mutual fund account |
(i | ) | 14.2 | 14.0 | 19.4 | 19.2 | |||||
| Equity securities |
32.5 | 31.2 | 35.0 | 29.2 | |||||||
| Total |
58.1 | 55.2 | 67.7 | 60.4 | |||||||
| (i) | A mutual fund account with an estimated fair value of £14.0 million and an unrealised loss of £0.2 million at 31 March 2004 was in a continuous unrealised loss position for more than 12 months. This impairment is considered temporary based on the nature of the investments. |
Proceeds, gross gains and gross losses from realised sales of available-for-sale securities using the specific identification method were as follows:
| Year ended 31 March |
|||||||||
| 2004 | 2003 | 2002 | |||||||
| £m |
£m |
£m |
|||||||
| Proceeds |
35.9 | 56.3 | 56.4 | ||||||
| Gross gains |
2.4 | 1.1 | 2.1 | ||||||
| Gross losses |
(1.2 | ) | (3.7 | ) | (5.6 | ) | |||
| Net gains/(losses) |
1.2 | (2.6 | ) | (3.5 | ) | ||||
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/(loss) for financial year under US GAAP and earnings/(loss) per share under US GAAP would have been reduced to the pro forma amounts below:
| 2004 |
2003 |
2002 |
|||||||
| Profit/(loss) for the financial year under US GAAP (£ million) |
741.6 | 789.3 | (887.0 | ) | |||||
| Reversal of APB 25 stock compensation expense (included within the ‘Other’ adjustment) (£ million) |
2.8 | 3.6 | 4.4 | ||||||
| Stock compensation expense calculated under FAS 123 (£ million) |
(4.6 | ) | (6.1 | ) | (7.4 | ) | |||
| Pro forma profit/(loss) for the financial year under US GAAP (£ million) |
739.8 | 786.8 | (890.0 | ) | |||||
| Basic earnings/(loss) per share under US GAAP |
40.54 | p | 42.81 | p | (48.26 | )p | |||
| Pro forma basic earnings/(loss) per share under US GAAP |
40.44 | p | 42.67 | p | (48.43 | )p | |||
| Diluted earnings/(loss) per share under US GAAP |
39.19 | p | 42.70 | p | (48.26 | )p | |||
| Pro forma diluted earnings/(loss) per share under US GAAP |
39.09 | p | 42.57 | p | (48.43 | )p | |||
The weighted average fair value of options granted during the year was £6.0 million (2003 £6.3 million, 2002 £8.6 million). The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions used:
| 2004 |
2003 |
2002 |
|||||||
| Dividend yield |
5.0 | % | 8.3 | % | 6.7 | % | |||
| Risk-free interest rate |
4.6 | % | 4.6 | % | 4.8 | % | |||
| Volatility |
24.9 | % | 30.0 | % | 30.0 | % | |||
| Expected life of the options (years) |
6 | 6 | 4 | ||||||
The weighted average life of the share options outstanding as at 31 March 2004, March 2003 and March 2002 was as follows:
| 2004 (years) |
2003 (years) |
2002 (years) | ||||
| ScottishPower Sharesave Schemes |
3 | 3 | 3 | |||
| Southern Water Sharesave Scheme |
— | — | 2 | |||
| Executive Share Option Scheme |
1 | 2 | 2 | |||
| Executive Share Option Plan 2001 |
8 | 9 | 9 | |||
| PacifiCorp Stock Incentive Plan |
5 | 6 | 6 | |||
134 ScottishPower Annual Report and Accounts 2003/04
34 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’) continued
(xv) Reclassifications
The reconciliations of profit/(loss) for the financial year and equity shareholders’ funds at the year end from UK GAAP to US GAAP only include those items which have a net effect on profit/(loss) or equity shareholders’ funds. There are other GAAP differences, not included in the reconciliations, which would affect the classification of assets and liabilities or of income and expenditure. The principal items which would have such an effect are as follows:
| (a) | under UK GAAP debt issue costs are deducted from the carrying value of the related debt instrument. US GAAP requires such costs to be included as an asset |
| (b) | under UK GAAP customer contributions in respect of fixed assets are generally credited to a separate deferred income account. Under US GAAP such contributions are netted off against the cost of the related fixed assets |
| (c) | under US GAAP, transmission and distribution costs would be included in cost of sales. Under UK GAAP these are included as a separate line item within the income statement |
| (d) | under UK GAAP, the investor’s interest in the turnover and results of a joint venture or associate are disclosed gross. The investor’s share of the interest and taxation are disclosed separately as a component of the group interest and taxation lines. Under US GAAP, the investor’s interest in the net results of joint ventures and associates is disclosed as a single line in the income statement, net of interest and taxation |
| (e) | the group implemented EITF No. 03-11 ‘Reporting Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes’ (“EITF 03-11”) on 1 January 2004. EITF 03-11 addresses whether realised gains and losses should be shown gross or net in the income statement for contracts that are not held for trading purposes but are derivatives subject to FAS 133. This issue led to a reduction in US GAAP reported turnover of £979.8 million (2003 £660.6 million, 2002 £948.6 million) with an equivalent reduction in cost of goods sold as a result of the netting approach adopted for contracts within the scope of the Issue. Under UK GAAP these items would be shown on a gross basis within the turnover and cost of sales line of the income statement |
| (f) | items included as exceptional items under UK GAAP were either classified as extraordinary items or operating items under US GAAP. However, following the implementation of Financial Accounting Standard No. 145 ‘Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections’ (“FAS 145”), on 1 April 2003 the classification of extraordinary items within the income statement under US GAAP has now been further restricted. Accordingly the costs of early debt repayments recorded as an extraordinary item in the year ended 31 March 2002 are no longer classified as an extraordinary item. This statement had no further impact on the group’s results and financial position under US GAAP. |
Consolidated statement of comprehensive income/(loss)
Under US GAAP, certain items shown as components of common equity must be more prominently reported in a separate statement as components of comprehensive income/(loss). The statement of total recognised gains and losses, which is the equivalent UK GAAP primary statement, is set out on page 92.
Consolidated statement of cash flows
The consolidated statement of cash flows prepared in accordance with FRS 1 (Revised) presents substantially the same information as that required under US GAAP. Under US GAAP, however, there are certain differences from UK GAAP with regard to the classification of items within the cash flow statement and with regard to the definition of cash and cash equivalents.
Under UK GAAP, cash flows are presented separately for operating activities, dividends received from joint ventures, returns on investments and servicing of finance, taxation, capital expenditure and financial investment, acquisitions and disposals, equity dividends paid, management of liquid resources, and financing. Under US GAAP, only three categories of cash flow activity are reported; operating activities, investing activities and financing activities. Cash flows from dividends received from joint ventures, returns on investments and servicing of finance and taxation would be included as operating activities under US GAAP. Equity dividends paid would be included under financing activities under US GAAP.
Under US GAAP, cash and cash equivalents are not offset by bank overdrafts repayable within 24 hours from the date of the advance, as is the case under UK GAAP and instead such bank overdrafts are classified within financing activities.
The consolidated cash flow statement prepared in conformity with UK GAAP is set out on page 93. In this statement an additional measure, free cash flow, is included which is not an accepted measure under US GAAP. This measure represents cash flow from operations after adjusting for dividends received from joint ventures, returns on investments and servicing of finance and taxation. UK investors regard free cash flow as the money available to management annually to be allocated among a number of options including capital expenditure, payments of dividends and the financing of acquisitions.
The consolidated statement of cash flows under US GAAP is set out below:
| 2003 | 2002 | |||||||||||
| 2004 | (As restated – Note 17) | |||||||||||
| Note |
£m |
£m |
£m |
|||||||||
| Cash inflow from operating activities |
1,364.0 | 1,412.9 | 1,248.4 | |||||||||
| Dividends received from joint ventures |
0.5 | 0.9 | 0.3 | |||||||||
| Returns on investments and servicing of finance |
(210.0 | ) | (297.0 | ) | (377.8 | ) | ||||||
| Taxation |
(121.8 | ) | (191.3 | ) | (85.0 | ) | ||||||
| Net cash provided by operating activities |
1,032.7 | 925.5 | 785.9 | |||||||||
| Capital expenditure and financial investment |
(831.2 | ) | (675.1 | ) | (1,142.5 | ) | ||||||
| Acquisitions and disposals |
(31.3 | ) | 1,792.8 | 98.7 | ||||||||
| Net cash (used)/provided in investing activities |
(862.5 | ) | 1,117.7 | (1,043.8 | ) | |||||||
| Financing |
(i | ) | 923.4 | (1,214.3 | ) | 923.3 | ||||||
| Movement in bank overdrafts |
1.5 | (4.9 | ) | (17.8 | ) | |||||||
| Equity dividends paid |
(394.4 | ) | (523.4 | ) | (496.8 | ) | ||||||
| Net cash provided/(required) by financing activities |
530.5 | (1,742.6 | ) | 408.7 | ||||||||
| Net increase in cash and cash equivalents |
700.7 | 300.6 | 150.8 | |||||||||
| Exchange movement on cash and cash equivalents |
(18.0 | ) | (16.8 | ) | (0.2 | ) | ||||||
| Cash and cash equivalents at beginning of financial year |
664.6 | 380.8 | 230.2 | |||||||||
| Cash and cash equivalents at end of financial year |
1,347.3 | 664.6 | 380.8 | |||||||||
All liquid investments with maturities of three months or less at the time of acquisition are considered to be cash equivalents.
| (i) | In 2004, cash flows from financing include £403.0 million for the repricing of cross-currency swaps and £76.1 million for the cancellation of cross-currency swaps. |
| 2004 | 2003 | 2002 | ||||
| £m |
£m |
£m | ||||
| Non-cash investing or financing activities |
||||||
| Movement in share of debt in joint arrangements |
6.4 | — | 100.5 | |||
| Amortisation of finance costs |
6.1 | 1.6 | 1.5 | |||
| Finance costs* |
14.2 | 4.0 | 5.6 | |||
| 26.7 | 5.6 | 107.6 | ||||
| * | These finance costs represent the effects of the RPI on bonds carrying an RPI coupon. |
ScottishPower Annual Report and Accounts 2003/04 135
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
34 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’) continued
Additional information required under US GAAP
(a) Infrastructure accounting
The group’s accounting policy in respect of Southern Water’s infrastructure assets and related maintenance and renewals expenditure, prior to the disposal of Southern Water, was not generally accepted under US GAAP which required historical cost depreciation accounting for these assets. The difference between the infrastructure renewals depreciation charge and depreciation accounting under US GAAP was not material to profit and equity shareholders’ funds. This difference no longer exists following the disposal of Southern Water in April 2002.
(b) Doubtful debts
The group estimates its provision for doubtful debts relating to trade debtors by a combination of two methods. Specific amounts are evaluated where information is available that a customer may be unable to meet its financial obligations. In these circumstances, assessment is made based on available information to record a specific provision against the amount receivable from that customer to adjust the carrying value of the debtor to the amount expected to be collected. In addition, a provision for doubtful debts within the portfolio of other debtors is made using historical experience and ageing analysis to estimate the provision required to reduce the carrying value of trade debtors to their estimated recoverable amounts. This process involves the use of assumptions and estimates which may differ from actual experience. The group provided £26.8 million, £36.8 million and £57.5 million for doubtful debts in 2003/04, 2002/03 and 2001/02 respectively. Write-offs against the provision for doubtful debts for uncollectable amounts were £45.6 million, £61.2 million and £36.6 million in 2003/04, 2002/03 and 2001/02 respectively.
(c) Deferred tax
The additional components of the estimated net deferred tax liability that would be recognised under US GAAP are as follows:
| 2004 | 2003 | |||||
| £m |
£m |
|||||
| Deferred tax liabilities: |
||||||
| Excess of book value over taxation value of fixed assets |
152.0 | 83.6 | ||||
| Other temporary differences |
139.5 | 99.3 | ||||
| 291.5 | 182.9 | |||||
| Deferred tax assets: |
||||||
| Other temporary differences |
(31.0 | ) | (4.1 | ) | ||
| Net deferred tax liability |
260.5 | 178.8 | ||||
| Analysed as follows: |
||||||
| Current |
5.6 | (4.1 | ) | |||
| Non-current |
254.9 | 182.9 | ||||
| 260.5 | 178.8 | |||||
The deferred tax balance in respect of leveraged leases at the year end is £81.8 million (2003 £101.1 million).
(d) Pensions
At 31 March 2004, ScottishPower had six statutorily approved defined benefit pension schemes, one statutorily approved defined contribution scheme and one unapproved scheme. Further details of the arrangements are given in Note 28.
Benefits under the UK defined benefit plans reflect each employee’s basic earnings, years of service and age at retirement. Funding of the defined benefit plans is based upon actuarially determined contributions, with members paying contributions at fixed rates and the employers meeting the balance of cost as determined by the scheme actuaries.
Reconciliations of the beginning and ending balances of the projected pension benefit obligation and the funded status of these plans for the years ending 31 March 2004, 31 March 2003 and 31 March 2002 are as follows:
| 2004 | 2003 | 2002 | |||||||
| £m |
£m |
£m |
|||||||
| Change in projected benefit obligation |
|||||||||
| Projected benefit obligation at beginning of year |
2,831.0 | 3,112.2 | 3,051.0 | ||||||
| Service cost (excluding plan participants’ contributions) |
45.0 | 52.6 | 62.2 | ||||||
| Interest cost |
154.8 | 168.6 | 182.5 | ||||||
| Plan amendments |
— | — | 12.6 | (ii) | |||||
| Special termination benefits |
— | (2.5 | )(i) | 0.6 | (iii) | ||||
| Plan participants’ contributions |
8.1 | 8.1 | 11.9 | ||||||
| Actuarial loss |
172.6 | 69.7 | 29.0 | ||||||
| Benefits paid |
(179.2 | ) | (191.5 | ) | (209.5 | ) | |||
| Settlements(iv) |
(0.3 | ) | (317.9 | ) | (29.0 | ) | |||
| Exchange |
(105.6 | ) | (68.3 | ) | 0.9 | ||||
| Projected benefit obligation at end of year |
2,926.4 | 2,831.0 | 3,112.2 | ||||||
| (i) | The period to commence the enhanced early retirement benefits under the Workforce Transition Retirement Program (“WTRP”) ended on 31 December 2002. A credit adjustment of £2.5 million for prior special termination benefits was necessary to reflect the impact of those participants who did not commence their WTRP benefits by 31 December 2002 because they revoked their earlier election. |
| (ii) | Ad hoc cost of living benefit increase for certain retired employees that was approved on 13 March 2002. |
| (iii) | The acquisition of PacifiCorp by ScottishPower triggered special termination benefits from the SERP during 2002. |
| (iv) | Assets and liabilities were transferred in 2004 and in 2002 to the PacifiCorp/IBEW Local Union 57 Retirement Trust Fund and in 2003 in relation to the sale of Southern Water. |
136 ScottishPower Annual Report and Accounts 2003/04
34 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’) continued
| 2004 | 2003 | 2002 | |||||||
| £m |
£m |
£m |
|||||||
| Change in plans’ assets |
|||||||||
| Fair value of plans’ assets at beginning of year |
2,204.2 | 3,204.6 | 3,586.6 | ||||||
| Actual return on plans’ assets |
469.1 | (509.8 | ) | (163.0 | ) | ||||
| Employer contributions |
43.2 | 27.2 | 18.5 | ||||||
| Plan participants’ contributions |
8.1 | 8.1 | 11.9 | ||||||
| Benefits paid |
(179.2 | ) | (191.5 | ) | (209.5 | ) | |||
| Settlements(i) |
(0.3 | ) | (278.5 | ) | (39.4 | ) | |||
| Exchange |
(60.9 | ) | (55.9 | ) | (0.5 | ) | |||
| Fair value of plans’ assets at end of year |
2,484.2 | 2,204.2 | 3,204.6 | ||||||
| (i) | Assets and liabilities were transferred in 2004 and in 2002 to the PacifiCorp/IBEW Local Union 57 Retirement Trust Fund and in 2003 in relation to the sale of Southern Water. |
| 2004 | 2003 | 2002 | |||||||
| £m |
£m |
£m |
|||||||
| Reconciliation of funded status of the plans to prepaid benefit cost |
|||||||||
| Funded status of the plans |
(442.2 | ) | (626.8 | ) | 92.4 | ||||
| Unrecognised net actuarial loss |
655.5 | 852.4 | 121.9 | ||||||
| Unrecognised prior service cost |
(0.9 | ) | (1.3 | ) | (1.5 | ) | |||
| Unrecognised transition obligation asset |
— | (0.9 | ) | (1.6 | ) | ||||
| Prepaid benefit cost |
212.4 | 223.4 | 211.2 | ||||||
| 2004 | 2003 | 2002 | |||||||
| £m |
£m |
£m |
|||||||
| Amounts recognised in balance sheet (UK arrangements) |
|||||||||
| Prepaid benefit cost(i) |
188.4 | — | 270.4 | ||||||
| Accrued benefit liability |
(96.2 | ) | (252.1 | ) | — | ||||
| Accumulated other comprehensive loss |
136.3 | 507.9 | — | ||||||
| Total recognised |
228.5 | 255.8 | 270.4 | ||||||
| (i) | £nil where scheme has accrued benefit liability or where asset value is below accumulated benefit obligation. |
| 2004 | 2003 | 2002 | |||||||
| £m |
£m |
£m |
|||||||
| Amounts recognised in balance sheet (US arrangements) |
|||||||||
| Accrued benefit liability |
(196.2 | ) | (241.9 | ) | (121.3 | ) | |||
| Accumulated other comprehensive loss |
71.6 | 67.1 | 62.1 | ||||||
| US regulatory assets(i) |
123.1 | 148.4 | — | ||||||
| Exchange |
(14.6 | ) | (6.0 | ) | — | ||||
| Total recognised |
(16.1 | ) | (32.4 | ) | (59.2 | ) | |||
| (i) | For the US pension arrangements the fair value of the plan assets was less than the accumulated benefit obligation. Under FAS 87 a minimum pension liability is then recognised. This liability was recorded as a non-cash increase of £123.1 million (2003 £148.4 million) to regulatory assets and £71.6 million (2003 £67.1 million) to accumulated other comprehensive loss. Accounting orders were received from the regulatory commissions in Utah, Oregon and Wyoming to classify most of this charge as a regulatory asset instead of a charge to other comprehensive income. The group also filed for similar treatment with the regulatory commission in Washington during the year ended 31 March 2004. This increase to regulatory assets will be adjusted in future periods as the difference between the fair value of the plan assets and the accumulated benefit obligation changes. |
The value of plan assets relative to the accumulated benefit obligation at the year end were as follows:
| Value of plan assets at 31 March 2004 |
Value of plan assets at 31 March 2003 |
Accumulated benefit obligation at 31 March 2004 |
Accumulated benefit obligation at 31 March 2003 | |||||
| £m |
£m |
£m |
£m | |||||
| ScottishPower |
1,538.9 | 1,310.5 | 1,535.2 | 1,438.4 | ||||
| Manweb |
529.2 | 449.2 | 612.4 | 563.0 | ||||
| Final Salary LifePlan |
16.0 | 12.8 | 12.7 | 11.3 | ||||
| PacifiCorp |
398.9 | 430.9 | 595.0 | 672.2 | ||||
The value of plan assets relative to the projected benefit obligation at the year end were as follows:
| Value of plan assets at 31 March 2004 |
Value of plan assets at 31 March 2003 |
Projected benefit obligation at 31 March 2004 |
Projected benefit obligation at 31 March 2003 | |||||
| £m |
£m |
£m |
£m | |||||
| ScottishPower |
1,538.9 | 1,310.5 | 1,587.5 | 1,487.3 | ||||
| Manweb |
529.2 | 449.2 | 641.8 | 591.0 | ||||
| Final Salary LifePlan |
16.0 | 12.8 | 15.3 | 13.5 | ||||
| PacifiCorp |
398.9 | 430.9 | 669.1 | 728.4 | ||||
ScottishPower Annual Report and Accounts 2003/04 137
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
34 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’) continued
The components of pension benefit costs for the years ended 31 March 2004, 2003 and 2002 were as follows:
| 31 March 2004 |
31 March 2003 |
31 March 2002 |
|||||||
| £m |
£m |
£m |
|||||||
| Service cost |
48.1 | (i) | 55.7 | (i) | 62.2 | ||||
| Curtailment/settlement cost |
— | 26.3 | (ii) | — | |||||
| Interest cost |
154.8 | 168.6 | 182.5 | ||||||
| Expected return on plans’ assets |
(165.3 | ) | (232.2 | ) | (261.2 | ) | |||
| Amortisation of experience losses/(gains) |
26.3 | 0.1 | (5.8 | ) | |||||
| Amortisation of prior service cost |
(0.2 | ) | — | (1.1 | ) | ||||
| Amortisation of transition obligation asset |
(0.9 | ) | (0.7 | ) | (0.9 | ) | |||
| Net periodic benefit cost/(credit) |
62.8 | 17.8 | (24.3 | ) | |||||
| (i) | Includes the contribution of £3.1 million (2003 £3.1 million) to the PacifiCorp/IBEW Local Union 57 Retirement Trust Fund. |
| (ii) | Sale of Southern Water, and consequent removal of pre-paid benefit cost in relation to this scheme. |
The group expects to contribute £23.3 million to the UK pension schemes and £36.9 million ($67.8 million) to the PacifiCorp pension scheme in the year ending 31 March 2005.
The actuarial assumptions adopted in arriving at the above figures are as follows:
| 31 March 2004* |
31 March 2003** |
31 March 2002*** | ||||
| UK arrangements – assumptions at: |
||||||
| Expected return on plans’ assets |
6.75% p.a. | 6.8% p.a. | 7.5% p.a. | |||
| Discount rate |
5.5% p.a. | 5.4% p.a. | 6.0% p.a. | |||
| Rate of earnings increase |
4.3% p.a. | 3.9% p.a. | 4.3% p.a. | |||
| Pension increases |
2.8% p.a. | 2.4% p.a. | 2.8% p.a. | |||
| 31 March 2004* |
31 March 2003** |
31 March 2002*** | ||||
| US arrangements – assumptions at: |
||||||
| Expected return on plans’ assets |
8.75% p.a. | 8.75% p.a. | 9.25% p.a. | |||
| Discount rate |
6.25% p.a. | 6.75% p.a. | 7.5% p.a. | |||
| Rate of earnings increase |
4.0% p.a. | 4.0% p.a. | 4.0% p.a. | |||
| Inflation rates |
3.0% p.a. | 3.0% p.a. | 4.0% p.a. | |||
The expected return on plans’ assets has been derived by consideration of the plans’ actual investments, as discussed in Note 28 (h).
| * | Assumptions used to determine benefit obligations at 31 March 2004. |
| ** | Assumptions used to determine net periodic benefit cost for year ended 31 March 2004 and benefit obligations at 31 March 2003. |
| *** | Assumptions used to determine net periodic benefit cost for year ended 31 March 2003 and benefit obligations at 31 March 2002. |
For the US arrangements the measurement dates for the years ended 31 March 2004, 2003 and 2002 are 31 December 2003, 2002 and 2001 respectively. The measurement dates for the UK arrangements are as at each respective year end.
(e) Other post-retirement benefits
PacifiCorp provides healthcare and life insurance benefits through various plans for eligible retirees. The cost of other post-retirement benefits is accrued over the active service period of employees. The transition obligation represents the unrecognised prior service cost and is being amortised over a period of 20 years. PacifiCorp funds other post-retirement benefit expense through a combination of funding vehicles. Over the period from 1 April 2003 to 31 March 2004, PacifiCorp made contributions totalling £16.5 million in respect of these arrangements. These funds are invested in common stocks, bonds and US government obligations.
The net periodic other post-retirement benefit cost and significant assumptions are summarised as follows:
| 2004 | 2003 | 2002 | |||||||
| £m |
£m |
£m |
|||||||
| Service cost |
4.4 | 3.6 | 3.6 | ||||||
| Interest cost |
20.2 | 22.1 | 20.0 | ||||||
| Expected return on plan assets |
(15.7 | ) | (18.5 | ) | (20.4 | ) | |||
| Amortisation of experience losses |
3.9 | 1.3 | — | ||||||
| Net periodic other post-retirement benefit cost |
12.8 | 8.5 | 3.2 | ||||||
The change in the accumulated other post-retirement benefit obligation, change in plan assets and funded status are as follows:
| 2004 | 2003 | 2002 | |||||||
| £m |
£m |
£m |
|||||||
| Change in accumulated other post-retirement benefit obligation |
|||||||||
| Accumulated other post-retirement benefit obligation at beginning of year |
330.4 | 331.3 | 268.0 | ||||||
| Service cost |
4.4 | 3.6 | 3.6 | ||||||
| Interest cost |
20.2 | 22.1 | 20.0 | ||||||
| Plan participants’ contributions |
4.0 | 3.9 | 3.8 | ||||||
| Special termination benefit gain |
— | (0.6 | )(i) | — | |||||
| Plan amendment |
0.4 | — | — | ||||||
| Actuarial loss |
12.7 | 26.4 | 53.8 | ||||||
| Benefits paid |
(22.3 | ) | (21.8 | ) | (18.8 | ) | |||
| Exchange |
(47.7 | ) | (34.5 | ) | 0.9 | ||||
| Accumulated other post-retirement obligation at end of year |
302.1 | 330.4 | 331.3 | ||||||
| (i) | The period to commence the enhanced early retirement benefits under the WTRP ended on 31 December 2002. A credit adjustment of £0.6 million for special termination benefits was necessary to reflect the impact of those participants who did not commence their WTRP benefits by 31 December 2002 because they revoked their earlier election. |
138 ScottishPower Annual Report and Accounts 2003/04
34 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’) continued
| 2004 | 2003 | 2002 | |||||||
| £m |
£m |
£m |
|||||||
| Change in plan assets |
|||||||||
| Plan assets at fair value at beginning of year |
137.9 | 184.9 | 201.9 | ||||||
| Actual return on plan assets |
30.0 | (13.8 | ) | (12.6 | ) | ||||
| Company contributions |
14.0 | 3.0 | 10.4 | ||||||
| Plan participants’ contributions |
4.0 | 3.9 | 3.8 | ||||||
| Benefits paid |
(22.3 | ) | (21.8 | ) | (18.8 | ) | |||
| Exchange |
(21.3 | ) | (18.3 | ) | 0.2 | ||||
| Plan assets at fair value at end of year |
142.3 | 137.9 | 184.9 | ||||||
| 2004 | 2003 | 2002 | |||||||
| £m |
£m |
£m |
|||||||
| Reconciliation of accrued other post-retirement costs and total amount recognised |
|||||||||
| Funded status of plan |
(159.8 | ) | (192.5 | ) | (146.4 | ) | |||
| PacifiCorp unrecognised net loss |
115.5 | 140.2 | 93.5 | ||||||
| PacifiCorp unrecognised prior service cost |
0.3 | — | — | ||||||
| Final contribution made after measurement date but before 31 March 2004 |
13.8 | 13.3 | — | ||||||
| Accrued other post-retirement benefit cost |
(30.2 | ) | (39.0 | ) | (52.9 | ) | |||
For other post-retirement benefits the group expects to contribute £17.2 million ($31.7 million) in the year ending 31 March 2005.
The actuarial assumptions adopted in arriving at the above figures are as follows:
| 31 March 2004* |
31 March 2003** |
31 March 2002*** |
|||||||
| US arrangements – assumptions at: |
|||||||||
| Expected return on plans’ assets |
8.75 | % p.a. | 8.75 | % p.a. | 9.25 | % p.a. | |||
| Discount rate |
6.25 | % p.a. | 6.75 | % p.a. | 7.50 | % p.a. | |||
| Initial healthcare cost trend – under 65 |
8.5 | % p.a. | 9.5 | % p.a. | 10.5 | % p.a. | |||
| Initial healthcare cost trend – over 65 |
10.5 | % p.a. | 11.5 | % p.a. | 12.5 | % p.a. | |||
| Initial healthcare cost trend rate |
5.0 | % p.a. | 5.0 | % p.a. | 5.0 | % p.a. | |||
| Year that rate reaches ultimate – under 65 |
2007 | 2007 | 2007 | ||||||
| Year that rate reaches ultimate – over 65 |
2009 | 2009 | 2009 | ||||||
The expected return on plans’ assets has been derived by consideration of the plans’ actual investments, as discussed in Note 28 (h).
| * | Assumptions used to determine other post-retirement benefit obligations at 31 March 2004. |
| ** | Assumptions used to determine net periodic other post-retirement benefit cost for year ended 31 March 2004 and benefit obligations at 31 March 2003. |
| *** | Assumptions used to determine net periodic other post-retirement benefit cost for year ended 31 March 2003 and benefit obligations at 31 March 2002. |
The measurement dates for the years ended 31 March 2004, 2003 and 2002 are 31 December 2003, 2002 and 2001, respectively.
The healthcare cost trend rate assumption has a significant effect on the amounts reported. Increasing the assumed healthcare cost trend rate by one percentage point would have increased the accumulated other post-retirement benefit obligation (the “APBO”) as at 31 March 2004 by £17.4 million (2003 £16.4 million, 2002 £18.5 million) and the annual net periodic other post-retirement benefit costs by £1.5 million (2003 £1.4 million, 2002 £1.3 million). Decreasing the assumed healthcare cost trend rate by one percentage point would have reduced the APBO as at 31 March 2004 by £14.7 million (2003 £14.3 million, 2002 £17.1 million), and the annual net periodic other post-retirement benefit costs by £1.3 million (2003 £1.2 million, 2002 £1.2 million).
Employee savings and stock ownership plan
PacifiCorp has an employee savings and stock ownership plan that qualifies as a tax-deferred arrangement under Section 401(a), 401(k), and 401(m) of the Internal Revenue Code. Participating US employees may defer up to 25% of their compensation, subject to certain regulatory limitations. This limit was raised to 50% in February 2004. Employees can select a variety of investment options including ScottishPower American Depository Shares (formerly PacifiCorp shares). PacifiCorp matches 50% of employee contributions on amounts deferred up to 6% of total compensation with that portion vesting over the initial five years of an employee’s participation in the Plan. Thereafter, PacifiCorp contributions vest immediately. PacifiCorp’s matching contribution is allocated based on the employee’s investment selections. PacifiCorp’s additional contribution is allocated based on the employee’s investment selections or to the money market fund if the employee has made no selections. PacifiCorp makes an additional contribution equal to a percentage of the employee’s eligible earnings. These contributions are immediately vested. Employer contributions to the savings plan were £10.5 million for the year ended 31 March 2004 (2003 £10.0 million, 2002 £14.7 million).
(f) Southern Water disposal
On 23 April 2002, the group completed the sale of Aspen 4 Limited (the holding company of Southern Water plc) to First Aqua Limited. A summary of the net assets disposed of calculated under US GAAP are detailed in the table below:
| £m |
|||
| Tangible fixed assets |
2,474.7 | ||
| Fixed asset investments |
1.9 | ||
| Current assets |
193.1 | ||
| Creditors: amounts falling due within one year |
(1,053.8 | ) | |
| Creditors: amounts falling due after more than one year |
|||
| Loans and other borrowings |
(100.0 | ) | |
| Provisions for liabilities and charges |
(366.6 | ) | |
| Deferred income |
(37.4 | ) | |
| Net assets |
1,111.9 | ||
ScottishPower Annual Report and Accounts 2003/04 139
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
34 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’) continued
(g) Asset retirement obligations and accrued environmental costs
(i) Asset retirement obligations
In June 2001, the FASB issued FAS 143 ‘Accounting for Asset Retirement Obligations’ (“FAS 143”) which became effective for the group on 1 April 2003. The group recorded asset retirement obligations for generation plants, landfills and coal mines which qualified as legal obligations under FAS 143. Under the requirements of the statement the group estimates its asset retirement obligations liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at the appropriate rate. The group then records an asset retirement obligations asset associated with the liability. The asset is depreciated over its expected life and the liability is accreted to the projected spending date. Changes in estimates could occur due to plan revisions, changes in estimated costs and changes in timing of the performance of reclamation activities. In addition, under US regulatory accounting requirements the group records removal costs as part of depreciation expense. Therefore, as a consequence of adopting FAS 143, the net difference between the previously recorded amounts that qualify as asset retirement obligations for regulatory purposes and the fair value amounts determined under FAS 143 have been recognised as a non-cash cumulative effect of change in accounting principle. The cumulative adjustment to US GAAP profits was £(0.6) million (net of tax). Similarly, the group’s US business recovers asset retirement costs through the rate making process and records a regulatory asset or liability on the balance sheet to account for the difference between asset retirement costs as currently approved in rates and costs under FAS 143. As at 31 March 2004 a regulatory asset of £2.1 million had been recorded for this purpose.
The following table details the movements on the group’s asset retirement obligation liability for the year ended 31 March 2004:
| £m |
|||
| Asset retirement obligation recognised at adoption on 1 April 2003 |
132.3 | ||
| New liabilities |
11.4 | ||
| Obligations utilised |
(10.8 | ) | |
| Accretion expense |
5.4 | ||
| Exchange |
(17.1 | ) | |
| Asset retirement obligation as at 31 March 2004 |
121.2 | ||
The current portion of the asset retirement obligation as at 31 March 2004 was £7.5 million.
The pro forma asset retirement obligation liability balances that would have been reported assuming FAS 143 had been adopted on 1 April 2001 rather than 1 April 2003 are as follows:
| £m | ||
| Pro forma asset retirement obligation liability as at 1 April 2001 |
152.3 | |
| Pro forma asset retirement obligation liability as at 31 March 2002 |
148.1 | |
The adoption of FAS 143 would have had no material impact on US GAAP net income or reported cash flows for the pro forma periods listed above.
The group had trust fund assets of £47.6 million at 31 March 2004 (2003 £43.3 million), relating to mine reclamation, including joint owner’s portions.
(ii) Accrued environmental costs
Estimates of environmental liabilities are principally based on reports prepared by external consultants. The ultimate cost of environmental disturbance is uncertain and there may be variances from these cost estimates, which could affect future results. Environmental liabilities are generally recorded on an undiscounted basis. These liabilities are recorded in the UK GAAP balance sheet within ‘Provisions for liabilities and charges – other provisions’ and the US GAAP liability as at 31 March 2004 was £20.3 million (2003 £35.7 million).
(h) Leveraged leases
The pre-tax income/(loss) from leveraged leases during the year was £2.9 million (2003 £(27.8) million), the tax charge/(credit) on the pre-tax income/(loss) was £0.9 million (2003 £(10.7) million) and the investment tax credit recognised in the income statement was £0.8 million (2003 £0.9 million).
(i) Commitments and contingencies
(i) Environmental issues
UK businesses
The group’s UK businesses are subject to numerous regulatory requirements with respect to the protection of the environment, including environmental laws which regulate the construction, operation and decommissioning of power stations, pursuant to legislation implementing environmental directives adopted by the EU and protocols agreed under the auspices of international bodies such as the United Nations Economic Commission for Europe. The group believes that it has taken and continues to take measures to comply with applicable laws and regulations for the protection of the environment. Applicable regulations and requirements pertaining to the environment change frequently, however, with the result that continued compliance may require material investments, or that the group’s costs and results of operation are less favourable than anticipated.
PacifiCorp
PacifiCorp is subject to numerous environmental laws including: the Federal Clean Air Act, as enforced by the Environmental Protection Agency and various state agencies; the 1990 Clean Air Act Amendments; the Endangered Species Act of 1973, particularly as it relates to certain potentially endangered species of fish; the Comprehensive Environmental Response, Compensation and Liability Act of 1980, relating to environmental cleanups; along with the Federal Resource Conservation and Recovery Act of 1976 and Clean Water Act relating to water quality. These laws could potentially impact future operations. For those contingencies identified at 31 March 2004, principally Clean Air matters, which are the subject of discussions with the United States Environmental Protection Agency and state regulatory authorities, future costs relating to these matters may be significant and consist primarily of capital expenditures. However, PacifiCorp expects these costs will be included within 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. Nearly all 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 £7.6 million in costs 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.
(j) Mine reclamation
PacifiCorp
All of PacifiCorp’s mining operations are subject to reclamation and closure requirements. Compliance with these requirements could result in higher expenditures for both capital improvements and operating costs.
140 ScottishPower Annual Report and Accounts 2003/04
34 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’) continued
(k) Deferred net power costs
PacifiCorp
At 31 March 2004, PacifiCorp had deferred net power costs for the states of Utah, Oregon and Idaho. While PacifiCorp is pursuing full recovery of these costs, there can be no assurance that this will be achieved. Denial of recovery would result in the write-off of £31.4 million of deferred net power costs (net of amortisation), under US GAAP, reported under US regulatory assets in the UK/US GAAP reconciliation of equity shareholders’ funds.
(l) Regulation
PacifiCorp
The Emerging Issues Task Force (“EITF”) of the FASB concluded in 1997 that FAS 71 should be discontinued when detailed legislation or regulatory orders regarding competition are issued. Additionally, the EITF concluded that regulatory assets and liabilities applicable to businesses being deregulated should be written-off unless their recovery is provided through future regulated cash flows. PacifiCorp continuously evaluates the appropriateness of applying FAS 71 to each of its jurisdictions. At 31 March 2004, the group concluded that FAS 71 was appropriate. However, if efforts to deregulate progress, the group may in the future be required to discontinue its application of FAS 71 to all or a portion of its business. Based on the group’s US regulatory net asset balance under US GAAP at 31 March 2004, if the group stopped applying FAS 71 to its remaining regulated US operations, it would have recorded an after tax loss of £445.0 million under US GAAP.
(m) Guarantees
In accordance with FASB Interpretation No. 45 (“FIN 45”) ‘Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others: an Interpretation of FASB Statements No. 5, 57 and 107 and rescission of FASB Interpretation No. 34’, the group is required to disclose certain guarantees as defined in FIN 45. These guarantees principally relate to the group’s disposal of its former operations and are typical of these types of transactions. Furthermore, disclosure is required under FIN 45 of guarantees even where the likelihood that a liability will crystallise is remote. FIN 45 also requires recognition of liabilities under US GAAP of the fair value of certain guarantees issued or modified after 31 December 2002. No such guarantees have been identified. The disclosures required to be made under FIN 45 are detailed below:
The group has entered into a number of transactions involving the sale of parts of its business and the purchase of certain businesses and assets in accordance with overall group strategy. These transactions include the disposal of Southern Water, the demerger of Thus plc, the sale and disposal of the group’s Appliance Retailing business and the disposal of other non-core activities.
It is standard practice in such transactions to obtain or grant contractual assurances, including in the form of warranties and indemnities. In conducting merger, disposal or acquisition transactions the group takes significant steps to quantify and mitigate risk at the outset of any transaction and as the transaction progresses. Steps include carrying out, or granting the facility for the conduct of, a thorough due diligence exercise to ascertain any likely liabilities and, where the group is the vendor, the use of caps and threshold levels for liability, inserting time limits on claim periods and detailed disclosure.
Under certain of the business disposals, indemnities under the Transfer of Undertakings (Protection of Employment) Regulations 1981 (“the Regulations”) are still outstanding. These indemnities relate to potential liabilities with respect to former employees of the group in relation to their period of employment in the group. Typically there is no maximum limit on claims under these indemnities.
Recourse via tax warranties and indemnities remains outstanding on the same basis as stated above and in relation to the disposal of ScottishPower Telecommunications (Services) Limited, a former subsidiary of Thus plc. These expire on 30 October 2005. The maximum financial exposure under these arrangements is £7.5 million. No claims have been intimated in relation to this arrangement and the directors consider it extremely unlikely that there will be any material financial exposure to the group under this arrangement.
On 23 April 2002, the group sold Aspen 4 Limited, the owner of the Southern Water group of companies. In such transactions it is standard practice for the vendor to give assurances, in the form of warranties and indemnities to the purchaser. In relation to this transaction the warranty liability period commenced on 23 April 2002 and ends on 23 April 2007 for environmental warranties and on 23 April 2009 for tax warranties. The warranty liability period for all other warranties expired on 23 April 2004. The sale and purchase agreement contains a number of limitations to and exclusions of liability and maximum financial exposure for breach of the warranties (apart from tax warranties) is capped at £900.0 million. For the tax warranties the maximum exposure is approximately £1,950.0 million. There are also minimum threshold claim levels to be reached before a potential claim arises at all and thereafter as to whether it can be made. The directors consider it extremely unlikely that there will be any material financial exposure to the group under these arrangements as a detailed due diligence exercise was carried out pre-disposal and detailed disclosures were made to the purchaser so as to make them aware of all relevant information concerning the business and, consequentially, to reduce the likelihood of claims being made against the group.
On 8 October 2001, certain business and assets of the group’s former Appliance Retailing business were sold and the remainder of the business was closed. In such transactions it is standard practice for the vendor to give assurances in the form of certain warranties and indemnities to the purchaser. In relation to this transaction the warranty liability period commenced on 8 October 2001 and ended on 8 October 2003 with the exception of taxation and pensions warranties which end on October 2007. Protection relating to the sale of the group’s former subsidiary, Domestic Appliance Insurance Limited (“DAIL”) was given in relation to any shortfall in the provisions for claims for which DAIL was liable, if any, under the “Cashback” warranty scheme. The stated limit for all warranty claims was £75.0 million. Although a potential claim was received prior to the deadline with respect to the adequacy of the cashback provisions in the DAIL accounts (and discussions have taken place with respect to such a claim) the directors consider it extremely unlikely that there will be any material financial exposure to the group under these arrangements. Under the transaction a number of properties were also assigned to the purchaser. The purchaser became insolvent in August 2003. By operation of law and through the putting in place of standard agreements at the time of the sale, the liability for rent and certain other items due under some of these lease arrangements have reverted to the group. The maximum liability to the group for rental payments in the event of insolvency of the purchaser was estimated at approximately £9.0 million per annum. Steps have been and are still being taken to mitigate the liability that arises from this, including surrendering leases to landlords and putting in place new tenants to take over the liability. It is thus extremely unlikely that the group will ultimately become liable to this extent.
On 3 August 2000, the group agreed to sell Powercor Australia Ltd. In such transactions it is standard practice for the vendor to give certain warranties and indemnities to the purchaser. The group agreed to indemnify the purchaser for any breaches of representations relating to tax warranties or tax claims as defined therein until August 2005. The indemnity is limited by a AUD$15.0 million (£6.2 million) basket, with the group liable for the excess over this amount only and an overall cap of AUD$300.0 million (£124.6 million). No claims have been intimated in relation to the above noted arrangements and the directors consider it extremely unlikely that there will be any material financial exposure to the group under these arrangements.
To the extent that claims based upon the arrangements below are limited by applicable statutes, the limitation periods generally vary from three to six years, depending on the jurisdiction and the nature of the claim.
In connection with the sale of PacifiCorp’s Montana service territory, PacifiCorp entered into a purchase and sale agreement with Flathead Electric Cooperative (“Flathead”) dated 9 October 1998. Under the agreement, PacifiCorp indemnified Flathead for losses, if any, occurring after the closing date and arising as a result of certain breaches of warranty or covenants. The indemnification has a cap of $10.1 million (£5.5 million) until October 2008 and a cap of $5.1 million (£2.8 million) thereafter (less expended costs to date). Two indemnity claims relating to environmental issues have been tendered, but remediation costs for this claim, if any, are not expected to create a material financial exposure for the group.
ScottishPower Annual Report and Accounts 2003/04 141
Accounts 2003/04
Notes to the Group Accounts continued
for the year ended 31 March 2004
34 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’) continued
On 15 October 2001, the group sold its synthetic fuels operation. In such transactions it is standard practice for the vendor to give certain warranties and indemnities to the purchaser. The group agreed to indemnify the purchaser from losses suffered as a result of fraud or breach of representation or warranty, within 30 days of the expiration of the applicable statutory period of limitations. The established basket and cap do not apply to the surviving representations and warranties. The group also agreed to indemnify the purchaser for tax liabilities up to the closing date; this indemnity also expires within 30 days of the expiration of the statutory period of limitations. No claims have been intimated in relation to the above noted arrangements and the directors consider it extremely unlikely that there will be any material financial exposure to the group under these arrangements.
On 9 February 1999, PacifiCorp Group Holdings Company agreed to sell TPC Corporation. In such transactions it is standard practice for the vendor to give certain warranties and indemnities to the purchaser. The group provided indemnification to the purchaser for breaches of representations and warranties relating to environmental matters, tax matters and employee benefits for a limited period with regard to the environmental matters which ended on 9 February 2004, and through the applicable statute of limitations on tax and employee benefit matters. The indemnification is limited to a $1.0 million (£0.5 million) basket, with the group liable for the excess over this amount only and an overall $10.0 million (£5.4 million) cap. In addition, certain special indemnities were provided with respect to certain specified matters. No claims have been intimated in relation to the above noted arrangements and the directors consider it extremely unlikely that there will be any material financial exposure to the group under these arrangements.
PacifiCorp and its subsidiaries have made certain commitments related to the decommissioning or reclamation of certain jointly-owned facilities and mine sites. The decommissioning guarantees require such companies to pay a proportionate share of the decommissioning costs based upon percentage of ownership. The mine reclamation obligations require such companies to pay the mining entity a proportionate share of the mine’s reclamation costs based on the amount of coal purchased by PacifiCorp and its subsidiaries. In the event of default by any of the other joint participants, such companies are potentially obliged to absorb, directly or by paying additional sums to the project entity, a share, or all, of the defaulting party’s liability. The group has recorded its estimated share of the decommissioning and reclamation obligations.
ScottishPower Energy Retail Limited (“SPERL”) has entered into an agreement with Lloyds TSB in relation to energy marketing and services. This agreement contains indemnities in relation to transfer of staff by operation of the Regulations from SPERL to Lloyds TSB. The maximum liability is limited to £5.0 million. No claims have been intimated.
Under certain cash collateral agreements, Automated Power Exchange (UK) Limited, UK Power Exchange and Elexon can draw down and use cash collateral in event of default situations including upon a change in credit rating. The maximum financial exposure under these arrangements is £13.4 million.
Under the group’s arrangements carried out in accordance with the standard terms and conditions of the International Swap Dealers Association, Inc. (“ISDA”) Master Agreement there is a provision that the group will indemnify the counter-party for certain withholding taxes incurred under relevant tax laws. A liability under this indemnification will only arise on the occurrence of certain changes to tax laws in the jurisdiction of a relevant counterparty. The directors are not aware of any such contemplated changes.
(n) Derivative Instruments and Hedging Activities
The group uses derivative instruments in the normal course of business, to offset fluctuations in earnings, cash flows and equity associated with movements in exchange rates, interest rates and commodity prices.
FAS 133 ‘Accounting for Derivative Instruments and Hedging Activities’, as amended by FAS 138, was adopted by the group with effect from 1 April 2001. In April 2003, the FASB issued FAS No. 149 ‘Amendment of Statement 133 on Derivative Instruments and Hedging Activities’, (“FAS 149”). This statement amends and clarifies financial reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. This statement was effective for contracts entered into or modified after 30 June 2003. In applying this statement, the group began marking-to-market certain transactions that were entered into after 30 June 2003 that, prior to the implementation of FAS 149, would have qualified for the normal purchase and normal sales exemption under FAS 133.
FAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. FAS 133 requires that an entity recognise all derivatives as either assets or liabilities in the consolidated balance sheet and measure those instruments at fair value. FAS 133 prescribes requirements for designation and documentation of hedging relationships and ongoing assessments of effectiveness in order to qualify for hedge accounting.
Hedge effectiveness is assessed consistently with the method and risk management strategy documented for each hedging relationship. On at least a quarterly basis, the group assesses the effectiveness of each hedging relationship retrospectively and prospectively to ensure that hedge accounting was appropriate for the prior period and continues to be appropriate for future periods. The group applies the short cut method of assessing effectiveness when possible. The group considers hedge accounting to be appropriate if the assessment of hedge effectiveness indicates that the change in fair value of the designated hedging instrument is 80% to 125% effective at offsetting the change in fair value arising on the hedged risk of the hedged item or transaction.
The effect of changes in fair value of certain derivative instruments entered into to hedge PacifiCorp’s future retail resource requirements are subject to regulation in the US and therefore are deferred pursuant to FAS 71. PacifiCorp requested and received deferred accounting orders for the effects of FAS 133 as it relates to the change in value of certain long-term wholesale electricity contracts not meeting the definition of normal purchases and normal sales contracts.
Categories of derivatives
Derivatives are classified into four categories: fair value hedges, cash flow hedges, overseas net investment hedges and trading.
If a derivative instrument qualifies as a fair value hedge the change in the fair value of the derivative and the change in the fair value of hedged risk arising on the hedged item is recorded in earnings. The corresponding change is recorded against the book values of the derivative and hedged item on the balance sheet.
If a derivative instrument qualifies as a cash flow hedge, the effective portion of the hedging instrument’s gain or loss is reported in shareholders’ funds under US GAAP (as a component of accumulated other comprehensive income) and is recognised in earnings in the period during which the transaction being hedged affects earnings. The ineffective portion of the derivative’s fair value change is recorded in earnings.
For derivative instruments designated as a hedge of the foreign currency risk in an overseas net investment, gains or losses due to fluctuations in foreign exchange rates are recorded in the cumulative translation adjustment within shareholders’ funds under US GAAP (as a component of accumulated other comprehensive income).
If a derivative instrument does not qualify as either a net investment hedge or a cash flow hedge under the applicable guidance, the change in the fair value of the derivative is immediately recognised in earnings or as an adjustment to the FAS 71 regulatory asset as appropriate.
Derivative instruments are not generally held by the company for speculative trading purposes. To the extent such instruments are held they are measured at fair value with gains or losses recorded in earnings. The net fair value of trading derivatives at 31 March 2004 was £0.6 million.
142 ScottishPower Annual Report and Accounts 2003/04
34 Summary of differences between UK and US Generally Accepted Accounting Principles (‘GAAP’) continued
Certain contracts that meet the definition of a derivative under FAS 133 may qualify as a normal purchase or a normal sale and be excluded from the scope of FAS 133. Specific criteria must be met in order for a contract that would otherwise be regarded as a derivative to qualify as a normal purchase or a normal sale. The group has evaluated all commodity contracts to determine if they meet the definition of a derivative and qualify as a normal purchase or a normal sale.
The group also evaluates contracts for “embedded” derivatives, and considers whether any embedded derivatives have to be separated from the underlying host contract and accounted for separately in accordance with FAS 133 requirements. Where embedded derivatives have terms that are not clearly and closely related to the terms of the host contract in which they are included, they are accounted for separately from the host contract as derivatives, with changes in the fair value recorded in earnings, to the extent that the hybrid instrument is not already accounted for at fair value.
Discontinued hedge accounting
When hedge accounting is discontinued due to the group’s determination that the derivative no longer qualifies as an effective fair value hedge, the group will continue to carry the derivative on the balance sheet at its fair value. The related hedged asset or liability will cease to be adjusted for changes in fair value relating to the previously hedged risk.
When the group discontinues hedge accounting in a cash flow hedge because it is no longer probable that the forecasted transaction will occur in the expected period, the gain or loss on the derivative remains in accumulated other comprehensive income and is reclassified into earnings when the forecasted transaction affects earnings. However, if it is probable that a forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter, the gains and losses that were accumulated in other comprehensive income will be recognised in earnings.
Where a derivative instrument ceases to meet the criteria for hedge accounting, any subsequent gains and losses are recognised in earnings.
Fair value hedges
The group seeks to maintain a desired level of floating rate debt, and uses interest rate and cross-currency swaps to manage interest rate and foreign currency risk arising from long-term debt obligations denominated in sterling and foreign currencies. The group does not exclude any component of derivative gains and losses from the assessment of hedge effectiveness. The ineffective portion of fair value hedges as at 31 March 2004 resulted in a loss of £0.7 million recorded for the year ended 31 March 2004.
Cash flow hedges
A desired level of fixed rate debt is maintained through the use of interest rate and cross-currency swaps. Foreign currency forward contracts are used to fix the exchange rate on future contracted purchases of assets. These transactions are accounted for as cash flow hedges. The group does not exclude any component of derivative gains and losses from the assessment of ineffectiveness. The amount of ineffectiveness for cash flow hedges recorded for the year ended 31 March 2004 was £nil. Net realised losses on cash flow hedges totalling £2.5 million were transferred from accumulated other comprehensive income into income during the year to match the underlying hedged items recognised in the income statement. The group estimates that losses of £6.3 million on cash flow hedges in place at the year end will be transferred from accumulated other comprehensive income into income during 2004/05.
Net investment hedges
The group uses foreign currency forwards and cross-currency swaps to protect the value of its investments in operations denominated in foreign currencies. The group excludes the spot-forward difference from the assessment of hedge effectiveness. In the year ended 31 March 2004 the group recorded a £295.9 million translation adjustment gain related to net investment hedges.
(o) Recent US accounting pronouncements
In January 2003, the FASB issued FASB Interpretation No. 46, ‘Consolidation of Variable-Interest Entities, an interpretation of Accounting Research Bulletin No.51’ (“FIN 46”), which was subsequently revised and became effective for the group on 1 April 2004. FIN 46 requires existing unconsolidated variable-interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. The group has considered the application of this standard to its operations and has completed an assessment of the impact of this standard. Following this review the group identified one variable interest entity which would be required to be consolidated and the necessary disclosures are given below.
PacifiCorp holds an undivided interest in 50.0% of the 474 MW Hermiston plant, procures 100.0% of the fuel input into the plant and subsequently acquires 100.0% of the generated electricity. Since PacifiCorp owns only 50.0% of the plant, it is required to purchase 50.0% of the generated electricity from the joint owner (in which PacifiCorp holds no equity interest) through a long-term purchase power agreement. As a result, PacifiCorp holds a variable-interest in the joint owner of the remaining 50.0% of the plant and is the primary beneficiary. However, PacifiCorp was unable to obtain the information necessary to consolidate the entity as the entity did not agree to supply the information due to the lack of a contractual obligation to do so. Electricity purchased from the joint owner for the year ended 31 March 2004 was £19.9 million (2003 £22.0 million, 2002 £23.1 million). The entity is operated by the equity owners and PacifiCorp has no risk of loss in relation to the entity in the event of a disaster.
In January and May 2004, the FASB issued FASB Staff Position No. 106-1 and FASB Staff Positon No. 106-2 ‘Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003’ (“FASB SP No. 106-1” and “FASB SP No. 106-2”). The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”) was signed into law in December 2003 and establishes a prescription drug benefit, as well as a federal subsidy to sponsors of retiree healthcare benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare’s prescription drug coverage. FASB SP No. 106-2 provides guidance on the accounting for the effects of the Medicare Act for employers that sponsor post-retirement healthcare plans that provide prescription drug benefits and requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. Under FASB SP No. 106-1, the group elected to defer accounting for the effects of the Medicare Act. This deferral remains in effect until the appropriate effective date of FASB SP No. 106-2. For entities that elected deferral and for which the impact is significant, FASB SP No. 106-2 is effective for the first interim or annual period beginning after 15 June 2004. For entities that will not recognise a significant impact, delayed recognition of the effects of the Medicare Act until the next regularly scheduled measurement date following issuance of FASB SP No. 106-2 is allowed. The group is still evaluating the impact of the Medicare Act. Accordingly, the group’s Accounts do not reflect the effects that may result from the Medicare Act.
ScottishPower Annual Report and Accounts 2003/04 143
Accounts 2003/04
as at 31 March 2004
| 2004 | 2003 (As restated – Note 35) |
|||||||
| Notes |
£m |
£m |
||||||
| Fixed assets |
||||||||
| Investments |
35 | 4,013.9 | 4,013.9 | |||||
| Current assets |
||||||||
| Debtors |
36 | 408.9 | 504.2 | |||||
| Short-term bank and other deposits |
1.0 | 1.7 | ||||||
| 409.9 | 505.9 | |||||||
| Creditors: amounts falling due within one year |
||||||||
| Loans and other borrowings |
37 | (491.4 | ) | (313.4 | ) | |||
| Other creditors |
38 | (145.5 | ) | (215.1 | ) | |||
| (636.9 | ) | (528.5 | ) | |||||
| Net current liabilities |
(227.0 | ) | (22.6 | ) | ||||
| Net assets |
3,786.9 | 3,991.3 | ||||||
| Called up share capital |
39 | 929.8 | 928.0 | |||||
| Share premium |
39 | 2,275.7 | 2,264.4 | |||||
| Capital redemption reserve |
39 | 18.3 | 18.3 | |||||
| Profit and loss account |
39 | 563.1 | 780.6 | |||||
| Equity shareholders’ funds |
39 | 3,786.9 | 3,991.3 | |||||
Approved by the Board on 25 May 2004 and signed on its behalf by
| /s/ Charles Miller Smith |
/s/ David Nish | |||
| Charles Miller Smith Chairman |
David Nish Finance Director | |||
The Accounting Policies and Definitions on pages 85 to 89, together with the Notes on pages 95 to 143 and 145 to 146 form part of these Accounts.
144 ScottishPower Annual Report and Accounts 2003/04
Notes to the Company Balance Sheet
as at 31 March 2004
| 35 Fixed asset investments | Subsidiary undertakings Shares |
Own shares held under trust |
Total | ||||||||
| Note |
£m |
£m |
£m |
||||||||
| Cost or valuation: |
|||||||||||
| At 1 April 2003 – as originally stated |
4,013.9 | 74.4 | 4,088.3 | ||||||||
| Prior year adjustment for UITF 38 |
(i | ) | – | (74.4 | ) | (74.4 | ) | ||||
| At 1 April 2003 – as restated and at 31 March 2004 |
4,013.9 | – | 4,013.9 | ||||||||
| (i) | UITF 38 has been applied in preparing these Accounts and comparative figures have been restated. The effect of this change in accounting policy on the group’s net assets is disclosed in Note 17. |
| 36 Debtors | 2004 | 2003 | ||
| £m |
£m | |||
| Amounts falling due within one year: |
||||
| Loans to subsidiary undertakings |
408.4 | 495.5 | ||
| Amounts due from subsidiary undertakings |
– | 8.6 | ||
| Interest due from subsidiary undertakings |
– | 0.1 | ||
| Other debtors |
0.5 | – | ||
| 408.9 | 504.2 | |||
| 37 Loans and other borrowings due within one year | 2004 | 2003 | ||
| £m |
£m | |||
| Loans from subsidiary undertakings |
491.4 | 313.4 | ||
| 38 Other creditors | 2004 | 2003 | ||
| £m |
£m | |||
| Amounts falling due within one year: |
||||
| Amounts due to subsidiary undertakings |
– | 8.6 | ||
| Interest due to subsidiary undertakings |
4.0 | 0.1 | ||
| Corporate tax |
24.7 | 65.1 | ||
| Accrued expenses |
3.9 | 9.1 | ||
| Proposed dividend |
112.9 | 132.2 | ||
| 145.5 | 215.1 | |||
| 39 Analysis of movements in shareholders’ funds | Number of shares |
Share capital |
Share premium |
Capital redemption reserve |
Profit and loss account |
Total | |||||||||||
| Note |
000s |
£m |
£m |
£m |
£m |
£m |
|||||||||||
| At 1 April 2003 – as originally stated |
1,855,933 | 928.0 | 2,264.4 | 18.3 | 855.0 | 4,065.7 | |||||||||||
| Prior year adjustment for UITF 38 |
(i | ) | – | – | – | – | (74.4 | ) | (74.4 | ) | |||||||
| At 1 April 2003 – as restated |
1,855,933 | 928.0 | 2,264.4 | 18.3 | 780.6 | 3,991.3 | |||||||||||
| Retained loss for the year |
– | – | – | – | (203.8 | ) | (203.8 | ) | |||||||||
| Share capital issued |
|||||||||||||||||
| – ESOP |
3,044 | 1.5 | 9.6 | – | – | 11.1 | |||||||||||
| – PacifiCorp Stock Incentive Plan |
562 | 0.3 | 1.7 | – | – | 2.0 | |||||||||||
| Consideration paid in respect of purchase of own shares held under trust |
– | – | – | – | (27.5 | ) | (27.5 | ) | |||||||||
| Credit in respect of employee share awards |
– | – | – | – | 13.4 | 13.4 | |||||||||||
| Consideration received in respect of sale of own shares held under trust |
– | – | – | – | 0.4 | 0.4 | |||||||||||
| At 31 March 2004 |
1,859,539 | 929.8 | 2,275.7 | 18.3 | 563.1 | 3,786.9 | |||||||||||
| (i) | UITF 38 has been applied in preparing these Accounts and comparative figures have been restated. The effect of this change in accounting policy on the group’s net assets is disclosed in Note 17. |
40 Profit and loss account
As permitted by Section 230 of the Companies Act 1985, the company has not presented its own profit and loss account. The company’s profit and loss account was approved by the Board on 25 May 2004. The profit for the financial year per the Accounts of the company was £171.3 million (2003 £76.4 million). The retained loss for the year of £203.8 million is stated after dividends of £375.1 million.
41 Contingent liabilities
In consideration of Scottish Power UK plc agreeing to subscribe for preference shares in SP Finance, the company has unconditionally and irrevocably agreed to:
| (a) | indemnify and hold harmless Scottish Power UK plc against any liability or loss incurred as a direct result of Scottish Power UK plc being or having been a member of SP Finance; and |
| (b) | procure that, for the period from 28 November 2002 until the date being 12 months after Scottish Power UK plc ceases to be a member of SP Finance, SP Finance shall not engage in any trading activities nor incur any liabilities other than in respect of its obligations under its Articles of Association. |
ScottishPower Annual Report and Accounts 2003/04 145
Accounts 2003/04
Principal Subsidiary Undertakings and Other Investments
| Subsidiary undertakings |
Class of share capital |
Proportion of shares held |
Activity | ||||
| Core Utility Solutions Limited |
‘A’ Ordinary shares £1* | 100 | % | Multi-utility design and construction service | |||
| CRE Energy Limited (Northern Ireland) |
Ordinary shares £1 | 100 | % | Wind-powered electricity generation | |||
| PacifiCorp (USA) |
Common stock | 100 | % | Regional electricity company | |||
| PacifiCorp Financial Services, Inc. (USA) |
Common stock | 100 | % | Finance company | |||
| PacifiCorp Group Holdings Company (USA) |
Common stock | 100 | % | Investment holding | |||
| PacifiCorp Holdings, Inc. (USA) |
Common stock | 100 | % | US holding company | |||
| PacifiCorp UK Limited** |
Voting shares $1 | 100 | % | Finance company | |||
| PPM Energy, Inc. (USA) |
Common stock | 100 | % | Wholesale power marketer, developer of | |||
| wind-power projects and provider of | |||||||
| natural gas/hub services | |||||||
| ScottishPower Energy Management Limited |
Ordinary shares £1 | 100 | % | Wholesale energy management company engaged in purchase and sale of electricity, | |||
| gas and coal | |||||||
| ScottishPower Energy Management (Agency) Limited |
Ordinary shares £1 | 100 | % | Agent for energy management activity of ScottishPower Energy Management | |||
| Limited and Scottish Power UK plc | |||||||
| ScottishPower Energy Retail Limited |
Ordinary shares £1 | 100 | % | Supply of electricity and gas to domestic and business customers | |||
| ScottishPower Generation Limited |
Ordinary shares £1 | 100 | % | Electricity generation | |||
| ScottishPower Insurance Limited (Isle of Man) |
Ordinary shares £1 | 100 | % | Insurance | |||
| ScottishPower Investments Limited |
Ordinary shares £1 | 100 | % | Holding company | |||
| ScottishPower NA 1 Limited# |
Ordinary shares £1 | 100 | % | Holding company | |||
| ScottishPower NA 2 Limited# |
Ordinary shares £1 | 100 | % | Holding company | |||
| Scottish Power Finance (Jersey) Limited (Jersey)# |
Ordinary shares of no par value | 100 | % | Finance Company | |||
| Scottish Power UK Holdings Limited# |
Ordinary shares 50p | 100 | % | Holding company | |||
| Scottish Power UK plc |
Ordinary shares 50p | 100 | % | Holding company | |||
| SP Dataserve Limited |
Ordinary shares £1 | 100 | % | Data collection, data aggregation, meter | |||
| operation and revenue protection | |||||||
| SP Distribution Limited |
Ordinary shares £1 | 100 | % | Ownership and operation of distribution | |||
| network within the ScottishPower area | |||||||
| SP Finance# |
Ordinary shares £0.01 | 100 | % | Finance company | |||
| SP Finance 2 Limited# |
Ordinary shares £1 | 100 | % | Holding company | |||
| SP Manweb plc |
Ordinary shares 50p | 100 | % | Ownership and operation of distribution | |||
| network within the Mersey and North Wales area | |||||||
| SP Power Systems Limited |
Ordinary shares £1 | 100 | % | Provision of asset management services | |||
| SP Transmission Limited |
Ordinary shares £1 | 100 | % | Ownership and operation of transmission | |||
| network within the ScottishPower area | |||||||
| Fixed asset investments |
|||||||
| Joint ventures |
|||||||
| CeltPower Limited |
‘B’ Ordinary shares £1* | 100 | % | Wind-powered electricity generation | |||
| Colorado Wind Ventures LLC (USA)## |
Not applicable | 50 | % | Wind-powered electricity generation | |||
| N.E.S.T. Makers Limited |
‘B’ Ordinary shares £1* | 100 | % | Energy efficiency agent for the‘fuel poor’/benefit market | |||
| ScotAsh Limited |
‘B’ Ordinary shares £1* | 100 | % | Sales of ash and ash-related cementitious products | |||
| Scottish Electricity Settlements Limited |
Ordinary shares £1 | 50 | % | Scottish electricity settlements | |||
| Shoreham Operations Company Limited |
‘B’ Ordinary shares £1* | 100 | % | Management services | |||
| South Coast Power Limited |
‘B’ Ordinary shares £1* | 100 | % | Electricity generation | |||
| Associated undertaking |
|||||||
| Wind Resources Limited |
‘B’ Ordinary shares £1*** | 100 | % | Wind-powered electricity generation |
Notes
| * | Represents 50% of the total issued share capital. |
| ** | 100% of the following classes of shares in PacifiCorp UK Limited are also indirectly held: ‘A’ Non-Voting Shares of $3,189.26 each; ‘B’ Non-Voting Shares of $3,446.41 each; ‘C’ Non-Voting Shares of $4,874.18 each; ‘D’ Non-Voting Shares of $2,924.90 each; ‘E’ Non-Voting Shares of $4,874.18 each; ‘F’ Non-Voting Shares of $3,883.54 each. |
| *** | Represents 45% of the total issued share capital. |
| # | The investment in this company is a direct holding of Scottish Power plc. |
| ## | Colorado Wind Ventures LLC elected to be treated as a partnership and therefore has no defined class of share capital. |
The directors consider that to give full particulars of all undertakings would lead to a statement of excessive length. The information above includes the undertakings whose results or financial position, in the opinion of the directors, principally affect the results or financial position of the group.
All companies are incorporated in Great Britain, unless otherwise stated.
146 ScottishPower Annual Report and Accounts 2003/04
to the members of Scottish Power plc
We have audited the Accounts which comprise the Accounting Policies and Definitions, the Group Profit and Loss Accounts, the Statement of Total Recognised Gains and Losses, the Note of Historical Cost Profits and Losses, the Reconciliation of Movements in Shareholders’ Funds, the Group Cash Flow Statement, the Reconciliation of Net Cash Flow to Movement in Net Debt, the Group Balance Sheet, the Statement of Principal Subsidiary Undertakings and Other Investments, the Company Balance Sheet and the related notes. We have also audited the disclosures required by Part 3 of Schedule 7A to the Companies Act 1985 contained in the Remuneration Report of the Directors (‘the auditable part’).
Respective responsibilities of directors and auditors
The directors’ responsibilities for preparing the Annual Report and Accounts in accordance with applicable United Kingdom law and accounting standards are set out in the statement of directors’ responsibilities. The directors are also responsible for preparing the Remuneration Report of the Directors.
Our responsibility is to audit the Accounts and the auditable part of the Remuneration Report of the Directors in accordance with relevant legal and regulatory requirements and United Kingdom Auditing Standards issued by the Auditing Practices Board. This report, including the opinion, has been prepared for and only for the company’s members as a body in accordance with Section 235 of the Companies Act 1985 and for no other purpose. We do not, in giving this opinion, accept or assume responsibility for any other purpose or to any other person to whom this report is shown or into whose hands it may come save where expressly agreed by our prior consent in writing.
We report to you our opinion as to whether the Accounts give a true and fair view and whether the Accounts and the auditable part of the Remuneration Report of the Directors have been properly prepared in accordance with the Companies Act 1985. We also report to you if, in our opinion, the Report of the Directors is not consistent with the Accounts, if the company has not kept proper accounting records, if we have not received all the information and explanations we require for our audit, or if information specified by law regarding directors’ remuneration and transactions is not disclosed.
We read the other information contained in the Annual Report and Accounts and consider the implications for our report if we become aware of any apparent misstatements or material inconsistencies with the Accounts. The other information comprises only the Chairman’s Statement, the Chief Executive’s Review, the Business Review, the Financial Review, the Corporate Governance statement, and the unaudited part of the Remuneration Report of the Directors.
We review whether the corporate governance statement reflects the company’s compliance with the seven provisions of the Combined Code issued in June 1998 specified for our review by the Listing Rules of the Financial Services Authority, and we report if it does not. We are not required to consider whether the board’s statements on internal control cover all risks and controls, or to form an opinion on the effectiveness of the company’s or group’s corporate governance procedures or its risk and control procedures.
Basis of audit opinion
We conducted our audit in accordance with Auditing Standards issued by the Auditing Practices Board. An audit includes examination, on a test basis, of evidence relevant to the amounts and disclosures in the Accounts and the auditable part of the Remuneration Report of the Directors. It also includes an assessment of the significant estimates and judgements made by the directors in the preparation of the Accounts, and of whether the accounting policies are appropriate to the group’s circumstances, consistently applied and adequately disclosed.
We planned and performed our audit so as to obtain all the information and explanations which we considered necessary in order to provide us with sufficient evidence to give reasonable assurance that the Accounts and the auditable part of the Remuneration Report of the Directors are free from material misstatement, whether caused by fraud or other irregularity or error. In forming our opinion we also evaluated the overall adequacy of the presentation of information in the Accounts.
Opinion
In our opinion:
| • | the Accounts give a true and fair view of the state of affairs of the company and the group at 31 March 2004 and of the profit and cash flows of the group for the year then ended; |
| • | the Accounts have been properly prepared in accordance with the Companies Act 1985; and |
| • | those parts of the Remuneration Report of the Directors required by Part 3 of Schedule 7A to the Companies Act 1985 have been properly prepared in accordance with the Companies Act 1985. |
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Chartered Accountants and Registered Auditors
Glasgow
25 May 2004
ScottishPower Annual Report and Accounts 2003/04 147
Accounts 2003/04
| Years ended 31 March | ||||||||||||||||||||
| 2004 | 2004 | 2003 (As Note 17) |
2002 (As Note 17) |
2001 (As Note 17) |
2000 (As restated – Note 17) |
|||||||||||||||
| Notes |
$ m |
£m |
£m |
£m |
£m |
£m |
||||||||||||||
| UK GAAP Information |
||||||||||||||||||||
| Profit and Loss Account Information: |
||||||||||||||||||||
| Turnover |
||||||||||||||||||||
| – continuing operations |
(a) | 10,666 | 5,797 | 5,247 | 5,523 | 5,410 | 3,110 | |||||||||||||
| – discontinued operations |
— | — | 27 | 791 | 939 | 1,005 | ||||||||||||||
| Total turnover |
10,666 | 5,797 | 5,274 | 6,314 | 6,349 | 4,115 | ||||||||||||||
| Operating profit |
||||||||||||||||||||
| – continuing operations |
(a) | 1,882 | 1,023 | 932 | 636 | 569 | 395 | |||||||||||||
| – discontinued operations |
— | — | 14 | 141 | 153 | 267 | ||||||||||||||
| Total operating profit |
1,882 | 1,023 | 946 | 777 | 722 | 662 | ||||||||||||||
| Operating profit (as adjusted) |
(b) | |||||||||||||||||||
| – continuing operations |
(a) | 2,118 | 1,151 | 1,071 | 801 | 815 | 676 | |||||||||||||
| – discontinued operations |
— | — | 14 | 143 | 155 | 285 | ||||||||||||||
| Total operating profit (as adjusted) |
2,118 | 1,151 | 1,085 | 944 | 970 | 961 | ||||||||||||||
| Profit/(loss) before taxation |
||||||||||||||||||||
| – continuing operations |
1,457 | 792 | 686 | 276 | 264 | 837 | ||||||||||||||
| – discontinued operations |
— | — | 11 | (1,215 | ) | 116 | 312 | |||||||||||||
| Total profit/(loss) before taxation |
1,457 | 792 | 697 | (939 | ) | 380 | 1,149 | |||||||||||||
| Profit before taxation (as adjusted) |
(b) | |||||||||||||||||||
| – continuing operations |
1,693 | 920 | 825 | 460 | 509 | 484 | ||||||||||||||
| – discontinued operations |
— | — | 11 | 107 | 119 | 252 | ||||||||||||||
| Total profit before taxation (as adjusted) |
1,693 | 920 | 836 | 567 | 628 | 736 | ||||||||||||||
| Profit/(loss) for financial year |
||||||||||||||||||||
| – continuing operations |
990 | 538 | 475 | 214 | 151 | 626 | ||||||||||||||
| – discontinued operations |
— | — | 8 | (1,201 | ) | 157 | 259 | |||||||||||||
| Total profit/(loss) for financial year |
990 | 538 | 483 | (987 | ) | 308 | 885 | |||||||||||||
| Cash dividends |
(690 | ) | (375 | ) | (530 | ) | (503 | ) | (477 | ) | (341 | ) | ||||||||
| Dividend in specie on demerger of Thus |
— | — | — | (437 | ) | — | — | |||||||||||||
| Balance Sheet Information: |
||||||||||||||||||||
| Total assets |
(h) | 25,403 | 13,806 | 13,858 | 16,244 | 16,910 | 15,446 | |||||||||||||
| Capital expenditure (net) |
(c) | 1,658 | 901 | 717 | 1,229 | 1,095 | 887 | |||||||||||||
| Long-term liabilities |
(h) | 12,853 | 6,985 | 7,244 | 8,314 | 7,788 | 6,890 | |||||||||||||
| Net debt |
6,854 | 3,725 | 4,321 | 6,208 | 5,285 | 4,842 | ||||||||||||||
| Equity shareholders’ funds |
(h) | 8,631 | 4,691 | 4,555 | 4,668 | 5,833 | 5,498 | |||||||||||||
| Net assets |
(h) | 8,743 | 4,752 | 4,629 | 4,755 | 6,119 | 5,798 | |||||||||||||
| Basic weighted average share capital (number of shares, million) |
1,830 | 1,830 | 1,844 | 1,838 | 1,830 | 1,390 | ||||||||||||||
| Diluted weighted average share capital (number of shares, million) |
1,890 | 1,890 | 1,848 | 1,840 | 1,837 | 1,399 | ||||||||||||||
| Ratios and statistics: |
||||||||||||||||||||
| Earnings/(loss) per ordinary share |
||||||||||||||||||||
| – continuing operations |
$0.541 | 29.40 | p | 25.76 | p | 11.65 | p | 8.26 | p | 45.05 | p | |||||||||
| – discontinued operations |
— | — | 0.41 | p | (65.36) | p | 8.54 | p | 18.64 | p | ||||||||||
| Total earnings/(loss) per ordinary share |
$0.541 | 29.40 | p | 26.17 | p | (53.71) | p | 16.80 | p | 63.69 | p | |||||||||
| Earnings per ordinary share (as adjusted) |
(e) | |||||||||||||||||||
| – continuing operations |
$0.67 | 36.40 | p | 33.30 | p | 21.04 | p | 19.19 | p | 23.65 | p | |||||||||
| – discontinued operations |
— | — | 0.41 | p | 5.08 | p | 8.67 | p | 14.32 | p | ||||||||||
| Total earnings per ordinary share (as adjusted) |
$0.67 | 36.40 | p | 33.71 | p | 26.12 | p | 27.86 | p | 37.97 | p | |||||||||
| Diluted earnings/(loss) per ordinary share |
$0.53 | 28.83 | p | 26.11 | p | (53.64 | )p | 16.74 | p | 63.25 | p | |||||||||
| Earnings/(loss) per ScottishPower ADS |
(d) | $2.17 | £1.18 | £1.05 | £(2.15) | £0.67 | £2.55 | |||||||||||||
| Earnings per ScottishPower ADS (as adjusted) |
(d),(e) | $2.69 | £1.46 | £1.35 | £1.04 | £1.11 | £1.52 | |||||||||||||
| Diluted earnings/(loss) per ScottishPower ADS |
(d) | $2.12 | £1.15 | £1.04 | £(2.15) | £0.67 | £2.53 | |||||||||||||
| Cash dividends per ScottishPower ordinary share |
$0.377 | 20.50 | p | 28.708 | p | 27.34 | p | 26.04 | p | 24.80 | p | |||||||||
| Cash dividends per ScottishPower ADS |
(d) | $1.42 | £0.82 | £1.15 | £1.09 | £1.04 | £0.99 | |||||||||||||
| Dividend cover (as adjusted) |
(e) | 1.78 | x | 1.78 | x | 1.17 | x | 0.95 | x | 1.07 | x | 1.55 | x | |||||||
| Interest cover (as adjusted) |
(e) | 4.9 | x | 4.9 | x | 4.3 | x | 2.5 | x | 3.0 | x | 4.2 | x | |||||||
| Gearing |
(f),(h) | 79 | % | 79 | % | 95 | % | 133 | % | 91 | % | 88 | % | |||||||
| US GAAP Information |
||||||||||||||||||||
| Total turnover |
(a), (i) | 8,863 | 4,817 | 4,613 | 5,365 | 5,537 | 4,069 | |||||||||||||
| Profit/(loss) for the financial year |
1,365 | 742 | 789 | (887) | 387 | 870 | ||||||||||||||
| Earnings/(loss) per ordinary share |
(g) | $0.7459 | 40.54 | p | 42.81 | p | (48.26) | p | 21.13 | p | 62.59 | p | ||||||||
| Diluted earnings/(loss) per ordinary share |
$0.7211 | 39.19 | p | 42.70 | p | (48.26) | p | 21.05 | p | 62.16 | p | |||||||||
| Earnings/(loss) per ScottishPower ADS |
(d),(g) | $2.98 | £1.62 | £1.71 | £(1.93) | £0.85 | £2.50 | |||||||||||||
| Diluted earnings/(loss) per ScottishPower ADS |
(d) | $2.89 | £1.57 | £1.71 | £(1.93) | £0.84 | £2.49 | |||||||||||||
| Total assets |
27,745 | 15,079 | 15,259 | 17,818 | 18,646 | 16,971 | ||||||||||||||
| Equity shareholders’ funds under US GAAP |
10,543 | 5,730 | 5,480 | 5,850 | 7,463 | 7,001 | ||||||||||||||
| (a) | The results for the financial year ended 31 March 2000 included turnover of £711.7 million, operating profit of £114.9 million and operating profit, before goodwill amortisation, of £151.7 million in respect of PacifiCorp for the period of the year following its acquisition on 29 November 1999. |
| (b) | Operating profit (as adjusted) and profit before taxation (as adjusted) exclude the effect of exceptional items and goodwill amortisation. |
| (c) | Capital expenditure is stated net of capital grants and customer contributions. |
| (d) | Earnings/(loss) and cash dividends per ScottishPower ADS have been calculated based on a ratio of four ScottishPower ordinary shares to one ScottishPower ADS. Cash dividends per ScottishPower ADS are shown based on the actual amounts in US dollars. |
| (e) | The adjusted figures for Earnings per ordinary share, Earnings per ScottishPower ADS, Dividend cover and Interest cover exclude the effects of exceptional items and goodwill amortisation as applicable. |
| (f) | Gearing is calculated by dividing net debt by equity shareholders’ funds. |
| (g) | As permitted under UK GAAP, earnings/(loss) per share have been presented including and excluding the impact of the exceptional items and goodwill amortisation to provide an additional measure of underlying performance. In accordance with US GAAP, earnings/(loss) per share have been presented based on US GAAP earnings, without adjustments for the impact of UK GAAP exceptional items and goodwill amortisation. Such additional measures of underlying performance are not permitted under US GAAP. |
| (h) | Prior year figures have been restated for the change in accounting policy in 2004 relating to own shares held under trust following implementation of UITF 38. |
| (i) | Prior year figures have been restated following the implementation of EITF No. 03 – 11 “Reporting Gains and Losses on Derivative Instruments that are subject to FAS 133 ‘Accounting for Derivative Instruments’ and Hedging Activities, and not held for trading purposes”. |
| (j) | Amounts for the financial year ended 31 March 2004 have been translated, solely for the convenience of the reader, at $1.84 to £1.00, the closing exchange rate on 31 March 2004. |
148 ScottishPower Annual Report and Accounts 2003/04
Glossary of Financial Terms and US Equivalents
| UK Financial Terms used in Annual Report & Accounts |
US equivalent or definition | |
| Accounts | Financial statements | |
| Associates | Equity investees | |
| Capital allowances | Tax depreciation | |
| Capital redemption reserve | Other additional capital | |
| Creditors | Accounts payable and accrued liabilities | |
| Creditors: amounts falling due within one year | Current liabilities | |
| Creditors: amounts falling due after more than one year | Long-term liabilities | |
| Employee share schemes | Employee stock benefit plans | |
| Employee costs | Payroll costs | |
| Finance lease | Capital lease | |
| Financial year | Fiscal year | |
| Fixed asset investments | Non-current investments | |
| Freehold | Ownership with absolute rights in perpetuity | |
| Gearing | Leverage | |
| Investment in associates and joint ventures | Securities of equity investees | |
| Loans to associates and joint ventures | Indebtedness of equity investees not current | |
| Net asset value | Book value | |
| Operating profit | Net operating income | |
| Other debtors | Other current assets | |
| Own work capitalised | Costs of group’s employees engaged in the construction of plant and equipment for internal use | |
| Profit | Income | |
| Profit and loss account (statement) | Income statement | |
| Profit and loss account (in the balance sheet) | Retained earnings | |
| Profit/(loss) for financial year | Net income/(loss) | |
| Profit on sale of fixed assets | Gain on disposal of non-current assets | |
| Provision for doubtful debts | Allowance for bad and doubtful accounts receivable | |
| Provisions | Long-term liabilities other than debt and specific accounts payable | |
| Recognised gains and losses (statement) | Comprehensive income | |
| Reserves | Shareholders’ equity other than paid-up capital | |
| Share premium account | Additional paid-in capital or paid-in surplus (not distributable) | |
| Shareholders’ funds | Shareholders’ equity | |
| Stocks | Inventories | |
| Tangible fixed assets | Property, plant and equipment | |
| Trade debtors | Accounts receivable (net) | |
| Turnover | Revenues |
ScottishPower Annual Report and Accounts 2003/04 149
Investor Information
Investor Information
1 Investor Information
2 Financial Calendar
3 Shareholder Services
Nature of Trading Market
The principal trading market for the ordinary shares of ScottishPower is the London Stock Exchange. In addition, American Depositary Shares (“ADSs”) (each of which represents four ordinary shares) have been issued by JPMorgan Chase Bank, as depositary (the “Depositary”) for the company’s ADSs, and are traded on the New York Stock Exchange following listing on 8 September 1997.
Table 48 sets out, for the periods indicated, the highest and lowest middle market quotations for the ordinary shares, as derived from Datastream and the range of high and low closing sale prices for ADSs, as reported by Bloomberg. The prices shown for previous years have been adjusted, where appropriate, for capital issues.
On 31 March 2004, there were 551 registered holders of 306,677 ordinary shares with an address in the US and 61,700 registered holders of 72,043,620 ADSs (equivalent to 288,174,480 ordinary shares). The combined holdings of these shareholders represented 15.51% of the total number of ordinary shares outstanding as at 31 March 2004. UK registered shareholders held 83.62% of the total number of ordinary shares, and all shareholders other than those registered in the UK or the US held 0.87% of the total number of ordinary shares outstanding as at 31 March 2004. As certain of the ordinary shares and ADSs are held by brokers and other nominees, these numbers may not be representative of the actual number of beneficial owners in the US or elsewhere or the number of ordinary shares or ADSs beneficially held by US persons.
Table 48 – Historical Share Prices
| Ordinary shares |
American Depositary Shares | |||||||
| Period |
High (p) |
Low (p) |
High ($) |
Low ($) | ||||
| 1999/00 |
586.70 | 350.66 | 38.88 | 22.50 | ||||
| 2000/01 |
561.83 | 411.62 | 34.69 | 25.06 | ||||
| 2001/02 |
521.84 | 350.00 | 30.24 | 20.10 | ||||
| 2002/03 |
||||||||
| First quarter |
416.00 | 342.00 | 24.28 | 20.40 | ||||
| Second quarter |
384.00 | 298.75 | 23.95 | 19.53 | ||||
| Third quarter |
373.00 | 336.00 | 23.42 | 21.00 | ||||
| Fourth quarter |
388.00 | 330.75 | 24.25 | 21.55 | ||||
| 2003/04 |
||||||||
| First quarter |
395.25 | 360.00 | 25.76 | 23.59 | ||||
| Second quarter |
374.75 | 351.00 | 24.76 | 22.93 | ||||
| Third quarter |
372.75 | 344.75 | 27.18 | 23.59 | ||||
| Fourth quarter |
380.75 | 350.75 | 28.58 | 26.25 | ||||
| October 2003 |
359.50 | 344.75 | 24.45 | 23.59 | ||||
| November 2003 |
365.25 | 351.00 | 25.20 | 23.82 | ||||
| December 2003 |
372.75 | 356.50 | 27.18 | 25.02 | ||||
| January 2004 |
374.00 | 354.00 | 27.30 | 26.25 | ||||
| February 2004 |
366.50 | 350.75 | 27.98 | 26.62 | ||||
| March 2004 |
380.75 | 363.75 | 28.58 | 26.90 | ||||
Note:
The past performance of the ordinary shares/ADSs is not necessarily indicative of future performance.
150 ScottishPower Annual Report and Accounts 2003/04
Table 49 – Analysis of Ordinary Shareholdings at 31 March 2004
| Range of holdings |
No. of shareholdings |
No. of shares | ||
| 1-100 |
19,078 | 730,701 | ||
| 101-200 |
165,849 | 27,482,010 | ||
| 201-600 |
175,173 | 54,360,853 | ||
| 601-1,000 |
37,935 | 29,629,831 | ||
| 1,001-5,000 |
47,231 | 88,273,532 | ||
| 5,001-100,000 |
4,093 | 59,053,897 | ||
| 100,001 and above |
678 | 1,600,008,099 | ||
| Total |
450,037 | 1,859,538,923 | ||
Share Capital and Options
As a result of the issue of shares to the Trustee of the Employee Share Ownership Plan and the exercise of options under the PacifiCorp Stock Incentive Plan, a total of 3,606,121 ordinary shares of 50p each were issued during the year. Accordingly, the number of ordinary shares in issue was 1,859,538,923 as at 31 March 2004. During the year, options over 2,758,331 ordinary shares were granted to 1,901 employees under the ScottishPower Share save Scheme. Options over a total of 5,892,280 ordinary shares were granted under the Executive Share Option Plan 2001. No options were granted under the PacifiCorp Stock Incentive Plan during the year. No options were granted under the Executive Share Option Scheme, which was replaced in 1996 by the introduction of the Long Term Incentive Plan (the “Plan”). Awards in respect of 1,100,213 shares were made under the Plan during the year and these awards are subject to the achievement of specified performance criteria. Details are contained in the Remuneration Report.
Between 31 March 2004 and 20 May 2004, a further 458,536 ordinary shares have been issued as a result of the allotments in respect of the Employee Share Ownership Plan and the PacifiCorp Stock Incentive Plan. At the Annual General Meeting of the company last year, shareholders granted authority to the directors to purchase up to 185,615,798 ordinary shares. The directors have not exercised this authority.
Redemption of Special Share
Following consultation with the company, the Secretary of State for Scotland has exercised his option to redeem the special rights non-voting redeemable preference share of £1 in the capital of the company (the “Special Share”) at par in accordance with the company’s articles of association (“the Articles”). The Special Share was issued at the time of privatisation and entitled the holder to certain special rights under the Articles. The redemption was effected on 5 May 2004, as announced by the company at the time. It is proposed that the Articles be amended to reflect the redemption at this year’s Annual General Meeting.
Substantial Shareholdings
As at 20 May 2004, the company had been notified that the following companies were substantial shareholders:
| Number of shares |
Percentage of issued share capital |
||||
| Capital Research and Management Company |
163,990,126 | 8.82 | % | ||
| Barclays plc |
82,509,124 | 4.44 | % | ||
| Legal & General Investment Management |
64,443,603 | 3.46 | % | ||
| Prudential plc |
59,711,655 | 3.21 | % |
The substantial shareholders enjoy the same voting rights as all other shareholders.
Control of Company
As far as is known to the company, it is not directly or indirectly owned or controlled by another corporation or by any foreign government.
As at 20 May 2004, no person known to the company, other than the substantial shareholders shown above, owned more than 5% of any class of the group’s voting securities.
As at 20 May 2004, the total amount of voting securities owned by directors and executive officers of ScottishPower as a group is shown in Table 50 below.
Table 50 – Voting Securities
| Title of class identity of group |
Amount owned |
Percentage of class |
|||
| Ordinary shares |
|||||
| Directors and officers |
|||||
| (19 persons) |
1,978,243 | 0.11 | % |
Full details of the directors’ interests in ScottishPower shares are shown in Tables 46 and 47 in the Remuneration Report. None of the officers had a beneficial interest in 1% or more of the issued share capital.
In addition, as at 20 May 2004, the directors and officers of the company, as a group, held options to purchase 4,911,768 ordinary shares, all of which were issued pursuant to the Executive Share Option Scheme, Executive Share Option Plan 2001, ScottishPower’s Sharesave Schemes or the PacifiCorp Stock Incentive Plan.
The company does not know of any arrangements the operation of which might result in a change in control of the group.
Exchange Rates
The group publishes its consolidated Accounts in pounds sterling. In this document, references to “pounds sterling”, “pounds”, “pence” or “p” are to UK currency and references to “US dollars”, “US$” or “$” are to US currency. Solely for the convenience of the reader, this report contains translations of certain pounds sterling amounts into US dollars at specified rates, or, if not so specified, at the Noon Buying Rate sourced from Datastream (“Noon Buying Rate”) on 31 March 2004 of £1.00 = $1.84. On 20 May 2004, the Noon Buying Rate was $1.77 to £1.00. No representation is made that the pound sterling amounts have been, could have been or could be converted into US dollars at the rates indicated or at any other rates.
ScottishPower Annual Report and Accounts 2003/04 151
Investor Information
Table 51 sets out, for the periods indicated, certain information concerning the Noon Buying Rate for US dollars per £1.00.
Table 51 – Historical Exchange Rates
| Period |
High |
Low |
Average1 |
Year end | ||||||||
| 1999/00 |
$ | 1.68 | $ | 1.55 | $ | 1.61 | $ | 1.59 | ||||
| 2000/01 |
$ | 1.61 | $ | 1.40 | $ | 1.52 | $ | 1.42 | ||||
| 2001/02 |
$ | 1.48 | $ | 1.37 | $ | 1.43 | $ | 1.42 | ||||
| 2002/03 |
$ | 1.65 | $ | 1.43 | $ | 1.55 | $ | 1.58 | ||||
| 2003/04 |
$ | 1.90 | $ | 1.55 | $ | 1.69 | $ | 1.84 | ||||
| October 2003 |
$ | 1.7025 | $ | 1.6598 | $ | 1.6786 | ||||||
| November 2003 |
$ | 1.7219 | $ | 1.6693 | $ | 1.6902 | ||||||
| December 2003 |
$ | 1.7842 | $ | 1.7200 | $ | 1.7526 | ||||||
| January 2004 |
$ | 1.8511 | $ | 1.7842 | $ | 1.8224 | ||||||
| February 2004 |
$ | 1.9045 | $ | 1.8182 | $ | 1.8659 | ||||||
| March 2004 |
$ | 1.8680 | $ | 1.7943 | $ | 1.8261 | ||||||
| Note: | 1 The average of the Noon Buying Rates on the last day of each month during the relevant period. |
Dividends
Although dividends were historically declared and paid and financial reports published semi-annually, following completion of the merger with PacifiCorp, the company moved to quarterly reporting and the quarterly payment of dividends.
A dividend of 6.25 pence per share on the ordinary shares will be paid on 28 June 2004 to shareholders on the register on 4 June 2004. This makes total dividends for the year of 20.5 pence per share. A dividend of $0.4453 per ADS will also be paid on 28 June 2004 to ADS holders of record on 4 June 2004. This makes total dividends for the year of $1.4165 per ADS.
With effect from the financial year commencing 1 April 2003, ScottishPower has targeted dividend cover, based on full year earnings excluding goodwill amortisation and exceptional items, in the range 1.5 – 2.0 times and ideally towards the middle of that range. ScottishPower has aimed to grow dividends broadly in line with earnings thereafter.
To implement this policy, in the absence of unforeseen circumstances, ScottishPower intends to pay an identical dividend for each of the first three quarters of each year, with the dividend for the fourth quarter representing the balance of the total dividend for each year. In respect of each of the quarters ending 30 June 2004, 30 September 2004 and 31 December 2004, ScottishPower aims to declare a dividend of 4.95 pence per share.
Table 52 sets out the dividends paid on ordinary shares and ADSs in respect of the past five financial years, excluding any associated UK tax credit in respect of such dividends. A person resident in the UK for tax purposes who receives a dividend from the company is generally entitled to a tax credit, currently at a rate of 1/9th of the dividend (“associated UK tax credit”). For further information, see “Taxation of Dividends”.
Table 52 – Historical Dividend Payments
| Notes |
2003/04 |
2002/03 |
2001/02 |
2000/01 |
1999/00 | ||||||||||||
| Pence per ordinary share |
1 | ||||||||||||||||
| Interim |
— | — | — | — | 8.27p | ||||||||||||
| Pre-completion |
— | — | — | — | 8.10p | ||||||||||||
| Quarter (29 Nov 1999 – 31 Dec 1999) |
— | — | — | — | 2.23p | ||||||||||||
| Quarter (1 Jan 2000 – 31 Mar 2000) |
— | — | — | — | 6.20p | ||||||||||||
| Quarter (1 April – 30 June) |
4.75p | 7.177p | 6.835p | 6.51p | — | ||||||||||||
| Quarter (1 July – 30 Sept) |
4.75p | 7.177p | 6.835p | 6.51p | — | ||||||||||||
| Quarter (1 Oct – 31 Dec) |
4.75p | 7.177p | 6.835p | 6.51p | — | ||||||||||||
| Quarter (1 Jan – 31 Mar ) |
6.25p | 7.177p | 6.835p | 6.51p | — | ||||||||||||
| Total |
20.50p | 28.708p | 27.34p | 26.04p | 24.80p | ||||||||||||
| US dollars per ADS |
1,2 | ||||||||||||||||
| Interim |
— | — | — | — | $ | 0.5324 | |||||||||||
| Pre-completion |
— | — | — | — | $ | 0.5215 | |||||||||||
| Quarter (29 Nov 1999 – 31 Dec 1999) |
— | — | — | — | $ | 0.1413 | |||||||||||
| Quarter (1 Jan 2000 – 31 Mar 2000) |
— | — | — | — | $ | 0.3856 | |||||||||||
| Quarter (1 April – 30 June) |
$ | 0.3032 | $ | 0.4472 | $ | 0.3907 | $ | 0.3928 | — | ||||||||
| Quarter (1 July – 30 Sept) |
$ | 0.3207 | $ | 0.4479 | $ | 0.3979 | $ | 0.3702 | — | ||||||||
| Quarter (1 Oct – 31 Dec) |
$ | 0.3473 | $ | 0.4708 | $ | 0.3863 | $ | 0.3805 | — | ||||||||
| Quarter (1 Jan – 31 Mar) |
$ | 0.4453 | $ | 0.4609 | $ | 0.3972 | $ | 0.3721 | — | ||||||||
| Total |
$ | 1.4165 | $ | 1.8268 | $ | 1.5721 | $ | 1.5156 | $ | 1.5808 | |||||||
Notes:
| 1 | Dividends per share and per ADS are shown net of any associated UK tax credit available to certain holders of ordinary shares and ADSs. See “Taxation of Dividends”. Dividends paid by the Depositary in respect of ADSs are paid in US dollars based on a market rate of exchange that differs from the Noon Buying Rate. |
| 2 | Calculated based on a ratio of four ordinary shares for one ADS. |
152 ScottishPower Annual Report and Accounts 2003/04
Memorandum and Articles of Association
The company’s Memorandum and Articles of Association, and amendments, will be filed with the company’s report to the US Securities and Exchange Commission on Form 20-F.
Documents on Display
You may read and copy documents referred to in this annual report that have been filed with the SEC at the SEC’s public reference room located at 450 Fifth Street, N.W., Washington, D.C., 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms and their copy charges. You may also access our reports to the SEC and some of the other information we file with or submit to the SEC electronically through the SEC’s website at www.sec.gov.
Exchange Controls and Other Limitations Affecting Security Holders
There are currently no UK laws, decrees or regulations that restrict the export or import of capital, including, but not limited to, foreign exchange capital restrictions, or that affect the remittance of dividends or other payments to non-UK resident holders of the company’s securities except as otherwise set forth in “Taxation”.
There are no limitations imposed by UK law or by the company’s Memorandum and Articles of Association that restrict the right of non-UK resident or non-UK citizen owners to hold or to vote the ordinary shares.
Taxation
The following discussion of UK tax and US federal income tax consequences is set forth with respect to US tax considerations in reliance upon the advice of Milbank, Tweed, Hadley & McCloy LLP, special US counsel to the company, and with respect to UK tax considerations in reliance upon the advice of Freshfields Bruckhaus Deringer, the company’s UK lawyers. The discussion is intended only as a summary of the principal US federal income tax and UK tax consequences to investors who hold the ADSs or ordinary shares as capital assets and does not purport to be a complete analysis or listing of all potential tax consequences of the purchase, ownership and disposition of ADSs or ordinary shares. The summary does not discuss special tax rules that may be applicable to certain classes of investors, including banks, insurance companies, tax exempt entities, dealers, traders who elect to mark-to-market, investors with a functional currency other than the US dollar, persons who hold ADSs as part of a hedge, straddle or conversion transaction, or holders of 10% or more of the voting stock of the company. The statements of UK and US tax laws and practices set out below are based on the laws in force and as interpreted by the relevant taxation authorities as of the date of this report. The statements are subject to any changes occurring after that date in UK or US law or practice, in the interpretation thereof by the relevant taxation authorities, or in any double taxation convention between the US and the UK.
On 24 July 2001, the US and the UK signed a new convention between the two countries for the avoidance of double taxation with respect to taxes on income and capital gains (the “New Income Tax Convention”). Instruments of ratification with respect to the New Income Tax Convention were exchanged on 31 March 2003, putting the New Income Tax Convention into force as from that date, subject to certain effective date provisions that result in the delayed implementation of certain provisions.
It is possible, however, for an investor to elect that the rules of the treaty in force prior to 1 April 2003 (the “Expiring Income Tax Convention”) have effect in its entirety with respect to that investor for a further twelve-month period from the date on which the provisions of the New Income Tax Convention would otherwise be effective. Prior distributions by the company since publication of our last annual statement on 7 May 2003 may therefore be governed by the rules of either the Expiring Income Tax Convention or the New Income Tax Convention depending upon whether an investor has elected for the twelve-month extension in respect of the Expiring Income Tax Convention. As a result, the following discussion considers both alternatives. The company believes, and the discussion therefore assumes, that it is not a passive foreign investment company for US federal income tax purposes.
Each investor is urged to consult their own tax advisor regarding the tax consequences of the purchase, ownership and disposition of ordinary shares or ADSs under the laws of the US, the UK and their constituent jurisdictions and any other jurisdiction where the investor may be subject to tax.
If the obligations contemplated by the Deposit Agreement are performed in accordance with its terms, it is expected that a beneficial owner of ADSs will be treated as the owner of the underlying ordinary shares for the purposes of the Expiring Income Tax Convention, the New Income Tax Convention and the US Internal Revenue Code of 1986, as amended (“Code”).
For the purposes of this summary, the term “US Holder” means a beneficial owner of the ADSs that is a US citizen or resident, a US domestic corporation or partnership, a trust subject to the control of a US person and the primary supervision of a US court, or an estate, the income of which is subject to US federal income tax regardless of its source.
For the purposes of this summary, the term “Eligible US Holder” means a US holder that is a resident of the US for the purposes of the Expiring Income Tax Convention and that satisfies the following conditions:
| • | is not also resident in the UK for UK tax purposes; |
| • | is not a corporation which, alone or together with one or more associated corporations, controls, directly or indirectly, 10% or more of the voting stock of the company; |
ScottishPower Annual Report and Accounts 2003/04 153
Investor Information
| • | whose holding of the ADSs is not attributable to a permanent establishment in the UK through which such holder carries on a business or with a fixed base in the UK from which such holder performs independent personal services; and |
| • | under certain circumstances, is not a company 25% or more of the capital of which is owned, directly or indirectly, by persons that are neither individual residents of, nor nationals of the US. |
Taxation of Dividends
Save as set out below in relation to the UK withholding tax applied to the UK tax credit (as defined below) arising under the Expiring Income Tax Convention, the company is not required to withhold any UK taxes from its dividend payments to US Holders. Therefore the amount of a dividend paid to a US Holder will not be reduced by any UK withholding tax.
Under the New Income Tax Convention, US Holders are not entitled to a UK tax credit with respect to dividends paid by the company on or after 1 May 2003. Notwithstanding this effective date, an Eligible US Holder may continue to claim a UK tax credit with respect to dividends paid before 1 May 2004, if the holder elects to apply all the provisions of the Expiring Income Tax Convention during such period. Each investor is urged to consult their own tax advisor regarding the tax consequences of electing to apply the Expiring Income Tax Convention in lieu of the New Income Tax Convention.
If a US Holder elects for the twelve-month extension to apply the Expiring Income Tax Convention, then, under UK tax law and the Expiring Income Tax Convention, an Eligible US Holder that makes the appropriate election with respect to dividends paid before 1 May 2004 is in theory entitled to an additional payment from the UK (“UK tax credit”) equal to 1/9th of the amount of any dividend paid by the company to the holder. While, as noted above, the dividend paid by the company is not subject to any UK withholding tax, under the Expiring Income Tax Convention and under current UK law, the UK tax credit that otherwise would be payable by the UK is completely offset by a UK withholding tax equal to 100% of that UK tax credit. Accordingly, US Holders will receive the full amount of any dividend declared by the company (without deduction for UK tax) but will not be entitled to an additional cash payment from the UK in respect of the UK tax credit. An Eligible US Holder who elects to claim a credit (as described below) against the holder’s US federal income tax liability with respect to the UK withholding tax imposed on the UK tax credit amount, is required to include, in addition to the gross amount of the dividend paid by the company, the amount of UK tax credit in taxable income for US federal income tax purposes, even though none of the amount of the UK tax credit is paid by the UK. An Eligible US Holder who so elects to include the amount of the UK tax credit in taxable income, generally will be entitled to credit against the holder’s US tax liability, the amount of the UK tax credit that the holder is deemed to have received, which US tax credit may result in a reduction in the holder’s effective US tax rate on the cash dividend received.
An Eligible US Holder is not required to affirmatively make a claim to the UK Inland Revenue to be entitled to the US foreign tax credit, although an Eligible US Holder electing to claim the credit must complete an Internal Revenue Service Form 8833 (Treaty Based Return Position Disclosure) and file such Form with the holder’s US federal income tax return for each year that the tax credit is claimed. Eligible US Holders that include the amount of the UK tax credit in gross income, but do not elect to claim foreign tax credits may instead claim a deduction for UK withholding tax deemed paid. For foreign tax credit limitation purposes, the dividend (grossed-up to include the UK tax deemed paid) will be income from sources outside the US. Each investor is urged to consult their own tax advisor regarding the tax consequences of electing to apply the Expiring Income Tax Convention in lieu of the New Income Tax Convention and whether any filings or other actions may be required to substantiate an Eligible US Holder’s foreign tax credit claim.
Following is a simplified numerical example of the US tax treatment of dividends paid to an Eligible US Holder who is subject to tax at a rate of 15% and is eligible for and claims a US tax credit for the complete amount of the UK tax credit:
| $ |
|||
| Dividend received |
90.00 | ||
| UK tax credit |
10.00 | ||
| US taxable income |
100.00 | ||
| US tax at 15% |
15.00 | ||
| US tax credit for UK withholding tax |
(10.00 | ) | |
| US tax liability |
5.00 | ||
| Cash dividend received |
90.00 | ||
| US tax liability |
(5.00 | ) | |
| After-tax cash amount |
85.00 | ||
| Approximate effective US tax rate on cash received |
5.6 | % | |
Note that the US federal income tax consequences of dividends paid to an Eligible US Holder will depend upon the holder’s particular circumstances and, consequently, the US federal income tax consequences applicable to a particular holder may differ from those set out in the above example and some US Holders may not be able to make full or partial use of the UK tax credit. Eligible US Holders are urged to consult their own tax advisers regarding the tax consequences to them of the payment of a dividend by the company.
The full procedures for determining and claiming a US tax credit, with respect to dividends received from a UK corporation, are outlined in US Internal Revenue Service Revenue Procedure 2000 – 13, 2000 – 6 I.R.B. 1.
A US Holder recognises income when the dividend is actually or constructively received by the holder, in the case of ordinary shares, or by the Depositary, in the case of ADSs. The dividend will not be eligible for the dividends received deduction generally allowed to US corporations in respect of dividends received from other US corporations. New tax legislation signed
154 ScottishPower Annual Report and Accounts 2003/04
into law on 28 May 2003, provides for a maximum 15% US tax rate on the dividend income of an individual US holder with respect to dividends paid by a domestic corporation or “qualified foreign corporation”. A qualified foreign corporation generally includes a foreign corporation if (i) its shares are readily tradable on an established securities market in the US or (ii) it is eligible for benefits under a comprehensive US income tax treaty. Clause (i) will apply with respect to ADSs if such ADSs are readily tradable on an established securities market in the US. Under these rules, the company should be treated as a qualified foreign corporation and, therefore, dividends paid to an individual US holder with respect to the ADSs should be taxed at a maximum rate of 15%. The maximum 15% tax rate is effective with respect to dividends included in income during the period beginning on or after 1 January 2003, and ending 31 December 2008.
Distributions in excess of current and accumulated earnings and profits, as determined for US federal income tax purposes, will be treated as a return of capital to the extent of the US Holder’s basis in the ordinary shares or ADSs and thereafter as a capital gain. In determining the amount of the distribution, a US Holder will use the spot currency exchange rate on the date the dividend is included in income. Any difference between that amount and the dollars actually received may constitute a foreign currency gain or loss. However, a US Holder that is an individual is not required to recognise a gain of less than $200 from the exchange of foreign currency in a “personal transaction” as defined in Section 988(e) of the Code.
If the US Holder is a US partnership, trust or estate, the UK tax credit will be available only to the extent that the income derived by such partnership, trust or estate is subject to US federal income tax as the income of a resident either in its hands or in the hands of its partners or beneficiaries, as the case may be. Whether holders of ADSs who reside in countries other than the US are entitled to a tax credit in respect of dividends on ADSs depends in general upon the provisions of conventions or agreements, if any, as may exist between such countries and the UK.
Taxation of Capital Gains
In general, for US tax purposes, US Holders of ADSs will be treated as the owners of the underlying ordinary shares that are represented by such ADSs and deposits and withdrawals of ordinary shares by US Holders in exchange for ADSs will not be treated as a sale or other disposition for US federal income tax purposes. Upon a sale or other disposition of ordinary shares or ADSs, US Holders will recognise a gain or loss for US federal income tax purposes in an amount equal to the difference between the US dollar value of the amount realised and the US Holder’s tax basis (determined in US dollars) in such ordinary shares or ADSs. Generally, such gain or loss will be a long-term capital gain or loss if the US Holder’s holding period for such ordinary shares or ADSs exceeds one year. Any such gain or loss generally will be income from sources within the US for foreign tax credit limitation purposes. Long-term capital gain for an individual US Holder is generally subject to a reduced rate of tax. With respect to sales occurring on or after 6 May 2003, but before 1 January 2009, the long-term capital gain tax rate for an individual US holder is 15%. For sales occurring before 6 May 2003, or after 31 December 2008, the long-term capital gain rate for an individual US holder is 20%.
A US Holder who is not resident or ordinarily resident for UK tax purposes in the UK will not generally be liable for UK tax on capital gains recognised on the sale or other disposition of ADSs or ordinary shares, unless the US Holder carries on a trade, profession or vocation in the UK through a branch or agency (or, in the case of a company, a permanent establishment) and the ADSs or ordinary shares are, or have been, used, held or acquired for the purposes of such trade, profession or vocation or such branch or agency (or, in the case of a company, such permanent establishment).
US citizens resident or ordinarily resident in the UK, US corporations resident in the UK by reason of their business being centrally managed or controlled in the UK and US citizens who or US corporations which are trading or carrying on a trade, profession or vocation in the UK through a branch or agency (or, in the case of a company, a permanent establishment) and who or which have used, held or acquired ADSs or ordinary shares for the purposes of such trade, profession or vocation or such branch or agency (or, in the case of a company, such permanent establishment) may be liable for both UK and US tax in respect of a gain on the disposal of the ADSs or ordinary shares, subject to any available exemption or relief. Relief may be available under the New Income Tax Convention (if the rules of such convention have effect in respect of such US Holder at the time of the sale or other disposition of the ADSs or ordinary shares) to the extent that the US Holder is resident in the US for the purposes of the New Income Tax Convention unless the ADSs or ordinary shares form part of the business property of a permanent establishment that such US Holder has or has had in the UK. Such holders may not be entitled to a tax credit against their US federal income tax liability for the amount of UK capital gains tax or UK corporation tax on chargeable gains, as the case may be, paid in respect of such gain unless the holder appropriately can apply the credit against tax due on income from foreign sources.
US Holders are urged to consult their own tax advisors regarding the tax consequences to them of a sale or other disposition of ADSs or ordinary shares.
US Information Reporting and Backup Withholding
In general, information reporting requirements will apply to dividend payments (or other taxable distributions) in respect of ordinary shares or ADSs made within the US to a non-corporate US person. Accordingly, individual US Holders will receive an annual statement showing the amount of taxable dividends (or other reportable distributions) paid to them during the year. “Backup withholding” will apply to such payments (i) if the holder or beneficial owner fails to provide an accurate taxpayer identification number in the manner required by US law and
ScottishPower Annual Report and Accounts 2003/04 155
Investor Information
applicable regulations, (ii) if there has been notification from the Internal Revenue Service of a failure by the holder or beneficial owner to report all interest or dividends required to be shown on its federal income tax returns or, (iii) in certain circumstances, if the holder or beneficial owner fails to comply with applicable certification requirements.
In general, payment of the proceeds from the sale of ordinary shares or ADSs to or through a US office of a broker is subject to both US backup withholding and information reporting requirements, unless the holder or beneficial owner establishes an exemption. Different rules apply to payments made outside the US through an office outside the US.
UK Inheritance Tax
An individual who is domiciled in the US for the purposes of the convention between the US and the UK for the avoidance of double taxation with respect to estate and gift taxes (“Estate Tax Convention”) and who is not a national of the UK for the purposes of the Estate Tax Convention will not generally be subject to UK inheritance tax in respect of the ADSs or ordinary shares on the individual’s death or on a gift of the ADSs or ordinary shares during the individual’s lifetime, unless the ADSs or ordinary shares are part of the business property of a permanent establishment of the individual in the UK or pertain to a fixed base in the UK of an individual who performs independent personal services. Special rules apply to ADSs or ordinary shares held in trust. In the exceptional case where the shares are subject both to UK inheritance tax and to US federal gift or estate tax, the Estate Tax Convention generally provides for the tax paid in the UK to be credited against tax paid in the US.
UK Stamp Duty and Stamp Duty Reserve Tax
In practice, no UK stamp duty need be paid on the acquisition or transfer of ADSs provided that any instrument of transfer is executed outside the UK and subsequently remains at all times outside the UK. An agreement to transfer ADSs will not, in practice, give rise to a liability to stamp duty reserve tax.
Subject to certain exceptions, a transfer on sale of ordinary shares, as opposed to ADSs will generally be subject to UK stamp duty at a rate of 0.5% (rounded up, if necessary, to the nearest £5) of the consideration given for the transfer. An agreement to transfer such shares will normally give rise to a charge to UK stamp duty reserve tax at a rate of 0.5% of the consideration payable for the transfer, provided that stamp duty reserve tax will not be payable if stamp duty has been paid. Where such ordinary shares are later transferred to the Depositary’s nominee, further stamp duty or stamp duty reserve tax will normally be payable at the rate of 1.5% (rounded up, if necessary, to the nearest £5) of the value of the ordinary shares at the time of the transfer.
A transfer of ordinary shares by the Depositary or its nominee to the relative ADS holder when the ADS holder is not transferring beneficial ownership gives rise to a UK stamp duty liability of £5 per transfer.
Taxation of Thus Demerger Dividend in Specie
Information pertaining to the tax position of shareholders following the demerger of Thus can be obtained from the Company Secretary at the company’s registered office and from the company’s website: www.scottishpower.com.
156 ScottishPower Annual Report and Accounts 2003/04
Investor Information
| 28 June 2004 |
Q4 Dividend payment date – US and UK (final dividend for the year ended 31 March 2004) | |
| 23 July 2004 |
Annual General Meeting | |
| 12 August 2004 |
Announcement of results for quarter ending 30 June 2004 – Q1 | |
| September 2004 |
Q1 Dividend payable | |
| November 2004 |
Announcement of results for quarter ending 30 September 2004 – Q2 | |
| December 2004 |
Q2 Dividend payable | |
| February 2005 |
Announcement of results for quarter ending 31 December 2004 – Q3 | |
| March 2005 |
Q3 Dividend payable | |
| May 2005 |
Announcement of Preliminary Results for the year ending 31 March 2005 | |
| June 2005 |
Q4 Dividend payable (final dividend for the year ending 31 March 2005) |
Annual General Meeting
The Annual General Meeting will be held at the Edinburgh Festival Theatre, 13/29 Nicolson Street, Edinburgh on Friday 23 July 2004 at 11.00 a.m. Details of the resolutions to be proposed at the Annual General Meeting are contained in the Notice of Meeting.
Quarterly Results
Copies of the quarterly results may be obtained, free of charge, on request from the Company Secretary at the company’s registered office or by e-mailing shareholderservices@scottishpower.com. Quarterly results will also be published on the company’s website: www.scottishpower.com
Half Year Results
The company, as permitted by the London Stock Exchange, publishes its half year results in one UK national newspaper. In 2004, it is expected that the half year results will be published in The Telegraph and on the company’s website. Copies of the half year results may be obtained, free of charge, on request from the Company Secretary at the company’s registered office or by e-mailing shareholderservices@scottishpower.com.
Annual Review
The Annual Review 2003/04 is also available on CD, free of charge, from the Company Secretary at the company’s registered office or by e-mailing shareholderservices@scottishpower.com.
Press Releases
Press releases and up-to-date information on the company can be found on the company’s website.
Environmental and Social Impact Report
Copies of the Environmental and Social Impact Report may be obtained, free of charge, on request from the Company Secretary at the company’s registered office or by e-mailing shareholderservices@scottishpower.com. This Report, together with fuller information about environmental, marketplace, community and workplace issues, is also published on the company’s website. The 2003/04 Report will be published in October 2004.
ScottishPower Annual Report and Accounts 2003/04 157
Investor Information
Ordinary Shares
Share Registration Enquiries
The Registrar
Lloyds TSB Registrars Scotland
PO Box 28506
Edinburgh EH4 1XZ
Tel: +44 (0)870 600 3999
Fax: +44 (0)870 600 3980
Textphone: +44 (0)870 600 3950
Website: www.shareview.co.uk
Dividend Reinvestment Plan
The Dividend Reinvestment Plan provides ordinary shareholders with the facility to invest cash dividends by purchasing further ScottishPower shares. For further details, please contact Lloyds TSB Registrars on 0870 241 3018.
Share Consolidation and ISAs
Share consolidation is a facility which allows a number of holdings, and especially family holdings, to be consolidated into one holding. This service is provided free of charge.
Individual Savings Accounts (“ISAs”) are suitable for UK resident private investors who wish to shelter their ScottishPower shares from Income and Capital Gains Tax. Details of the ScottishPower ISA service are available from Lloyds TSB at the following address. Alternatively, please call the ISA helpline on 0870 242 4244.
Lloyds TSB Registrars ISAs
The Causeway
Worthing BN99 6UY
Share Dealing
ScottishPower ordinary shares may be bought or sold at competitive rates by post or telephone. For further details, please contact Stocktrade on 0845 601 0979, quoting LOW C0070.
American Depositary Shares (“ADSs”)
Exchange and Stock Transfer Enquiries
JPMorgan Chase Bank
Shareholder Relations
PO Box 43013
Providence, RI 02940-3013
Tel: 1 (866) SCOTADR (Toll Free)
1 (866) 726 8237 (Toll Free)
+1 (781) 575 2678 (Outside US not Toll Free)
Fax: +1 (781) 575 4082
Website: www.adr.com/shareholder
Dividend Reinvestment Plan
Global Invest Direct
Global Invest Direct is the Direct Share Purchase and Dividend Reinvestment Plan for ADS holders which allows existing and first time investors to purchase ADSs without a broker. Global Invest Direct allows investors to make initial and ongoing investments in the company by providing investors with the convenience of investing directly in ScottishPower’s ADSs. For further details, please contact JPMorgan Chase Bank as detailed above.
Authorised Representative for US Federal Securities Laws
The authorised representative for ScottishPower for US federal securities law purposes is:
Puglisi & Associates
850 Library Avenue, Suite 204
PO Box 885
Newark, Delaware 19715
158 ScottishPower Annual Report and Accounts 2003/04
| Accounting |
||
| developments |
58 | |
| policies and definitions |
56 – 58, 85 – 88 | |
| Acquisition |
102(11,12), 105(15) | |
| American Depositary Shares |
150, 158 | |
| Annual General Meeting |
157 | |
| Audit Committee |
64, 67 | |
| Audit Report |
147 | |
| Balance sheets |
||
| company |
144 | |
| group |
94 | |
| Board of Directors |
62 | |
| Borrowings |
109 – 114 (20) | |
| Business |
||
| description of |
9 – 17 | |
| reviews – 2003/04 |
39 – 42 | |
| reviews – 2002/03 |
44 – 46 | |
| strategy |
5, 8, 9 | |
| Capital commitments |
127 (30b) | |
| Capital expenditure |
5, 38, 104 (14b) | |
| Capital gains tax |
155 | |
| Cash flow |
||
| acquisitions and disposals |
102(11,12) | |
| analysis |
101(10) | |
| commentary |
38 | |
| group statement |
93 | |
| US GAAP |
135(34) | |
| Chairman’s Statement |
2 | |
| Charitable contributions |
16 | |
| Chief Executive’s Review |
4 | |
| Contingent liabilities |
126(29), 145(41) | |
| Corporate governance |
65 | |
| Corporate social responsibility |
8, 70 | |
| Creditor payment policy and practice |
55 | |
| Creditors |
114(21),145(37) | |
| Currencies, accounting policy |
89 | |
| Debt (net) |
||
| analysis |
103(13) | |
| reconciliation to net cash flow |
93 | |
| Debtors |
108(19), 145(36) | |
| Deferred income |
116(24) | |
| Deferred tax |
99(6), 115(22) | |
| Depreciation |
||
| accounting policy |
87 | |
| by segment |
96 (1c) | |
| Directors |
||
| executive |
63 | |
| non-executive |
62 | |
| pensions |
75, 80 | |
| remuneration |
72 | |
| report |
2 – 84 | |
| responsibilities for accounts |
84 | |
| service contracts |
76 | |
| share options |
74, 81 | |
| shareholdings |
73, 81 | |
| Dividends |
||
| in specie |
44, 100 (8b) | |
| per ADS |
||
| per ordinary share |
3, 5, 100 (8a) | |
| payment dates |
157 | |
| Divisions |
||
| Infrastructure |
3, 7, 12 | |
| UK |
3, 8, 13 | |
| Earnings and dividends |
||
| 2003/04 |
38 | |
| 2002/03 |
44 | |
| Earnings per ordinary share |
3, 5, 99 – 100 (7) | |
| Employees |
||
| numbers and costs |
15, 97(3) | |
| policies, UK and US |
15, 26 | |
| Environment |
||
| accounting policy |
89 | |
| policy approach |
15 | |
| regulation |
24 | |
| Exceptional items |
43, 98(4) | |
| Executive Team |
63, 68 | |
| Financial |
||
| commitments |
49,126(30) | |
| guarantees |
141 – 142 (34) | |
| review |
33 – 61 | |
| Financial instruments |
||
| accounting policies |
86 | |
| analysis |
109 – 114 (20) | |
| Five Year Summary |
148 | |
| Fixed assets |
||
| intangible |
105(15) | |
| investments |
88,107(17), 145(35) | |
| tangible |
87, 106(16) | |
| Glossary |
||
| of financial terms |
149 | |
| of general terms |
160 – 161 | |
| Going concern |
49 | |
| Goodwill |
||
| accounting policy |
87 | |
| analysis |
105(15) | |
| Grants and contributions |
||
| accounting policy |
89 | |
| analysis |
116(24) | |
| Health and safety |
3, 8, 27 | |
| Inheritance tax |
156 | |
| Interest charge (net) |
||
| accounting policy |
86 | |
| analysis |
98(5) | |
| Interest and Taxation |
||
| 2003/04 |
37 – 38 | |
| 2002/03 |
43 – 44 | |
| Internal control |
68 | |
| Investor information |
150 | |
| Leased assets, accounting policy |
88 | |
| Litigation |
29 | |
| Loans and other borrowings |
109 – 114 (20) | |
| Long Term Incentive Plan |
74, 81 | |
| Minority interests |
120(27) | |
| Net asset value per share |
104 (14a) | |
| Net assets by segment |
104 (14a) | |
| Nomination Committee |
64, 66 | |
| Off Balance Sheet Arrangements |
61 | |
| Operating profit |
||
| analysis |
96(2) | |
| by segment |
95 (1b) | |
| reconciliation to net operating cash flows |
100(9) | |
| Own shares held under trust |
88 | |
| PacifiCorp |
3, 6, 10 | |
| PPM |
3, 8, 14 | |
| Pensions |
||
| accounting policy |
56, 58, 89 | |
| analysis |
120 –126 (28), 136 –139 (34) | |
| costs |
19, 28, 55 | |
| Political donations and expenditure |
70 | |
| Post-retirement benefits |
||
| accounting policy |
89 | |
| analysis |
123 (28h), 138 – 139 (34e) | |
| Profit and loss account |
||
| company |
145(40) | |
| group |
90 – 91 | |
| Property |
16 | |
| Provisions for liabilities and charges |
115(22), 115(23) | |
| Recognised gains and losses |
92 | |
| Registrar |
158 | |
| Regulation |
||
| electricity and gas UK |
22 | |
| electricity US |
17 | |
| employment |
26 | |
| environmental UK |
25 | |
| environmental US |
24 | |
| Related party transactions |
128(31) | |
| Remuneration Committee |
||
| membership |
64 | |
| report |
72 | |
| Research and development |
46, 96(2) | |
| Reserves |
119(26), 145(39) | |
| Risk management |
49 – 54 | |
| Safe harbor |
84 | |
| Segmental information |
95 – 96 (1), 104 (14) | |
| Share capital |
116 – 119 (25), 145 (39) | |
| Share options |
117 (25b), 151 | |
| Share premium |
119(26), 145(39) | |
| Shareholder services |
158 | |
| Shareholders’ funds |
||
| analysis |
119(26), 145(39) | |
| reconciliation |
92 | |
| Shareholdings, analysis |
151 | |
| Southern Water |
102(11, 12), 129(32) | |
| Stocks |
||
| accounting policy |
88 | |
| analysis |
108(18) | |
| Substantial shareholdings |
151 | |
| Taxation |
||
| accounting policy |
87 | |
| analysis |
99(6) | |
| commentary |
37, 44 | |
| deferred |
99(6), 115(22) | |
| of dividends |
154 | |
| Thus |
9, 129(33) | |
| Total assets by segment |
104 (14c) | |
| Treasury |
46 – 49 | |
| Turnover |
||
| accounting policy |
86 | |
| by segment |
95 (1a) | |
| US GAAP |
130 – 143 (34) | |
| US regulatory assets |
88, 131(34) |
Figures in brackets refer to Notes to the Group Accounts
ScottishPower Annual Report and Accounts 2003/04 159
ADS – American Depositary Share (US)
ASB – Accounting Standards Board (UK)
The Authority – The Gas and Electricity Markets Authority, the UK regulatory body (UK)
Baseload – the level of system demand for electricity which is generally present on a day-to-day basis
BE – British Energy plc (UK)
BETTA – British Electricity Trading and Transmission Arrangements, proposals for the introduction of a Great Britain-wide electricity market which are currently the subject of legislation before the UK Parliament
Billion – one thousand million (1,000,000,000)
British Isles – The United Kingdom and The Republic of Ireland
Churn – the turnover of existing customers leaving, and new customers joining, the company’s customer list
Combined Code – guidelines setting out corporate governance principles for UK listed companies (UK)
CO2 – carbon dioxide
CPUC – The California Public Utilities Commission, the regulatory body in California (US)
Carrying charges – costs, mainly interest but including some transaction costs and professional charges, arising from the deferment of costs for later recovery (US)
Company – Scottish Power plc
Competition Commission – the UK regulatory body concerned with competition policy and the abuse of market power (UK)
Deferred power costs – variances from the expected level of power purchase costs and related cost inputs which have been recognised by regulatory authorities as possibly or actually eligible for recovery in rates (US)
DG – Distributed Generation, the process of generating electricity from relatively large numbers of individually modest generation assets, rather than concentrating generation in major power plants
Distribution – the transfer of electricity from the transmission system to customers (US equivalent is Power Distribution)
DSM – Demand Side Management, encouraging customers to reduce their electricity consumption
DTI – The Department of Trade and Industry, a UK government department which, among other responsibilities, has a leading role in UK Government oversight of energy policy (UK)
EA – The Environment Agency, the environmental regulator for England & Wales (UK)
EBIT – earnings before interest and tax, excluding goodwill amortisation
EBITDA – earnings before interest, tax, depreciation, goodwill amortisation and deferred income released to the profit and loss account
EC – European Commission, the administrative arm of the European Union institutions
EIB – European Investment Bank
EITF – The Emerging Issues Task Force of the Financial Accounting Standards Board (US)
EPA – The Environmental Protection Agency (US)
ESOP – Employee Share Ownership Plan (UK)
ETO – The Energy Trust of Oregon, a body established to deliver demand side management services in Oregon (US)
EU – European Union, the body of 25 states bound by treaty to cooperate in aspects of the management of their affairs
Executive Team – a standing committee of the Board which assists the Chief Executive and, in particular, oversees much of the group’s risk management activities
ExSOP – Executive Share Option Scheme open to the company’s executive directors and senior managers
Fair value – the amount for which an asset could be exchanged, or a liability settled, between knowledgeable, willing parties in an arm’s length transaction
FAS – Financial Accounting Standard (US)
FASB – Financial Accounting Standards Board (US)
FERC – The Federal Energy Regulatory Commission, the US federal energy regulator (US)
FRS – Financial Reporting Standard (UK)
401(k) – a tax-beneficial savings plan available to US-domiciled employees (US)
FPA – The Federal Power Act (US)
GAAP – Generally Accepted Accounting Principles, these vary between the the UK (“UK GAAP”) and US (“US GAAP”)
Gas – natural gas
GERC – The Group Energy Risk Committee
Giga (G) – one thousand million (1,000,000,000) units
Great Britain – England, Scotland and Wales
Group – Scottish Power plc and its consolidated subsidiaries
Guaranteed Standards – standards of performance agreed between the company and Ofgem for transmission, distribution and supply (UK)
Hedging – undertaking transactions to guard against the risk of loss
Home area – the geographical area in which a company was previously the sole licensed supplier of residential customers (UK)
Hub services – a generic term describing various fee-based transactions carried out by a gas storage operator, for example, parking and loaning gas to meet balancing needs or “wheeling” gas from one pipeline to another at the storage location
Hydroelectric – the generic description for generating plants making use of the movement of water as their energy source
IAS – International Accounting Standard
IASB – International Accounting Standards Board
160 ScottishPower Annual Report and Accounts 2003/04
IFRS – International Financial Reporting Standard
Interconnectors – the high voltage links connecting the transmission system of Scotland with those of England & Wales and Northern Ireland (UK)
IPUC – The Idaho Public Utility Commission, the regulatory body in Idaho (US)
IRP – Integrated Resource Plan, a consolidated review of anticipated future requirements used as a context within which to assess individual proposals for new generation or conservation initiatives (US)
ISA – Individual Savings Account (UK)
Kilo (k) – one thousand (1,000) units
LBG – London Benchmarking Group, a body which manages a standard for the reporting of aspects of corporate social responsibility amongst over 80 leading UK companies (UK)
LTIP – Long Term Incentive Plan
Mark-to-market – the adjustment made to record an asset or a liability at its fair market value
Mega (M) – one million (1,000,000) units
MSP – the multi-state process through which PacifiCorp’s and the six states it serves are working to clarify roles and responsibilities concerning the regulation of PacifiCorps’ business activities (US)
MVA – Mega-Volt-amperes, a measure of network capacity
Nameplate rating – the designed capability of a generating plant
NEA – Nuclear Energy Agreement, between British Energy, ScottishPower and Scottish and Southern (UK)
NETA – The New Energy Trading Arrangements introduced in March 2001 (UK)
NOx – oxides of Nitrogen
Ofgem – The Office of Gas and Electricity Markets, which provides administrative support to the UK regulatory authority (UK)
OPUC – The Oregon Public Utility Commission, the regulatory body in Oregon (US)
Peaking plant – generating assets designed to top-up the overall system to meet the higher levels of demand for electricity which occur from time to time
PED – Public Electricity Distributor, the licensed electricity distribution network operator in each authorised area (UK)
plc – public limited company (UK)
Power production – the US term for the generation of electricity
PSCs – Public Services Commissions, the individual bodies which regulate utilities in each of the states (US)
PSP – the Personal Shareholding Policy under which executive directors and key senior managers are expected to build up and retain a shareholding in the company
PTCs – Production Tax Credits which make renewable generation cost-effective in many US electricity markets (US)
Rates – the US term for Tariffs
RECs – Renewable Energy Certificates, tradable confirmation that generation output qualifies for recognition as being from renewable sources and therefore attracts incentives in many electricity markets (US)
Refurbishment of networks – activity designed to replace and modernise network assets without materially increasing their capacity, generally undertaken to improve cost-efficiency, reliability or other aspects of service quality
Reinforcement of networks – activity designed to increase the capacity of network assets, generally undertaken to cope with increased customer demand
Renewables – sources of electricity generation which use naturally occurring or self-regenerating inputs, examples include wind and hydroelectric power
Retail sales – the supply of electricity or gas to end-user consumers
RFP – Requests for Proposals, the formal tendering process through which specific proposals are sought for the provision of new generation or conservation requirements (US)
ROCs – Renewables Obligation Certificates, tradable confirmation that generation output qualifies for recognition towards a supplier’s obligation to provide a defined proportion of its total electricity supplies from renewable sources (UK)
ROE – Return on Equity, a US regulatory measure intended to establish the return to shareholders (US)
RPI – the Retail Price Index, the equivalent of the US Consumer Price Index –CPI (UK)
RTO – Regional Transmission Organization, the generic name for regional organisations being developed in response to FERC Order 2000 to manage electricity transmission on a regional basis (US)
Sarbanes-Oxley Act – an act of 2002 which regulates various aspects of corporate standards (US)
SEC – The Securities and Exchange Commission, the US federal regulator of corporate affairs (US)
SEE – social, environmental and ethical
SEPA – The Scottish Environment Protection Agency, the environmental regulator for Scotland (UK)
SERP – The Supplemental Executive Retirement Plan which provides additional retirement benefits as an incentive to selected US managers and highly compensated employees
6 Sigma – a business process improvement methodology used to seek out potential productivity and service quality gains
SO2 – sulphur dioxide
SPUK – Scottish Power UK plc, the non-trading holding company for most of the group’s UK companies (UK)
SSAP – Statement of Standard Accounting Practice (UK)
Stipulation – or stipulation agreement, a term used in the US regulatory context to describe an agreement reached between parties which is then submitted for consideration by the regulatory authority (US)
Tera (T) – indicates a measure of 1012, for example terawatthours
ScottishPower Annual Report and Accounts 2003/04 161
Glossary
Thermal – the generic description for generating plants burning coal, gas, black liquor and the like, or using geothermal energy
Transmission – the transfer of electricity from power stations to the distribution system
Transportation (of gas) – transfer of gas from on-shore terminals to consumers through the national pipeline network (UK)
TSR – Total Shareholder Return, the return provided by capital appreciation and dividend reinvestment over a period
UITF – The Urgent Issues Task Force of the Accounting Standards Board (UK)
UK – United Kingdom, comprising England, Scotland, Wales and Northern Ireland
UPSC – The Utah Public Service Commission, the regulatory authority in Utah (US)
US – United States of America
VaR – Value-at-Risk, a statistically-based measure of the potential financial loss on a price exposure position used to provide a consistent measure of risk across the group
Volt (V) – Unit of electrical potential
WACC – weighted average cost of capital
Watt (W) – Unit of electrical power, the rate at which electricity is produced or used
Watt hour (Wh) – Unit of electrical energy, the production or consumption of one Watt for one hour
Wholesale sales – the supply of bulk electricity or gas to parties other than end-user customers
Windfarms – groups of wind-driven turbines used to generate electricity
WPSC – The Wyoming Public Service Commission, the regulatory authority in Wyoming (US)
WUTC – The Washington Utilities and Transportation Commission, the regulatory authority in Washington (US)
| Metres |
Yards | |||||
| Conversion factors |
0.91 | 1 | 1.09 | |||
| Km |
Miles | |||||
| 1.61 | 1 | 0.62 | ||||
| Litres |
US Gallons | |||||
| 3.78 | 1 | 0.26 | ||||
162 ScottishPower Annual Report and Accounts 2003/04
Scottish Power plc
Registered Office: 1 Atlantic Quay, Glasgow G2 8SP
Registered in Scotland No: 193794
For press releases and up-to-date information visit our website www.scottishpower.com