3rd Quarter 200001

1
3rd Quarter 2000-01
1 February 2001
2
Ian RussellDeputy Chief Executive
3
Agenda

• Highlights Ian Russell
• Q3 Financial Review David Nish
• US Business update Ian Russell

4
Highlights

• Continued strong progress withUS Transition Plan
• Restoration of Hunter expected in May
• Vigorously pursuing regulatory recovery of US
  excess power costs
• Good financial and operating performance from UK
  businesses

5
Supply Strategy

• Exhaustively researched, tested andanalysed
  various propositions
• Would involve substantial investment andinitial
  losses
• Insufficient returns for shareholders
• Closure of Royal Bank of Scotland joint venture
• Exit from telecoms trial

Insufficient value in cross selling
6
Cross Selling Economics

• Telco RBoS JV
• Value At best 10 / 1/4 of original
  Potential customer / annum target
• Time to positive 4 years plus 4 years plus cash
  flow
• Competitive BT Pricing? e-bank pricing
  uncertainty and branding?

7
Refocusing on Energy Supply

• Success of dual fuel offering
• Focus on cost efficiency
• Excellent customer service
• Retention of new e-business skills

Deliver higher value through arefocused energy
supply strategy
8
Agenda

• Highlights Ian Russell
• Q3 Financial Review David Nish
• US Business update Ian Russell

9
David NishFinance Director
10
Financial Highlights

• Turnover up by 1,932m to 4,569m
• Operating profit 116m higher at 697m
• Profit before tax unchanged at 441m
• Earnings per share down 25 at 21.1p, reflecting
  UK regulation and Hunter outage
• Annualised dividend per share up 5 to 19.53p

Nine months to 31 December 2000
Before goodwill amortisation and exceptional
items
11
Operating Profit Reconciliation
m
Operating profit 1999/00 581 PacifiCorp 236
Impact of UK regulation on revenues (101) Thus
(40) Cost savings in UK businesses 30
Other (9) Operating profit 2000/01 697
Before goodwill amortisation and exceptional
items Thus quoted pre minority interests
Nine months to 31 December 2000
12
Operating Profit
1999/00 m
2000/01 m
1999/00 Restated m
Generation 35 31 31 Power Systems 222 254 273 Ener
gy Supply 28 33 14 Southern Water 169 213 213 Thus
(49 (9 (9 Other 8 11 11 UK Total 413 533 533 Pa
cifiCorp 284 48 48 Group Total 697 581 581
)
)
)
Before goodwill amortisation and exceptional
items Thus quoted pre minority interests
Nine months to 31 December 2000
13
PacifiCorp Operating Profit
m
Reported Q3 operating profit 284 Impact of Hunter
outage 45 Estimated excess power costs
88 Underlying Q3 operating profit 417
PacifiCorp underlying performanceahead of
expectation
Before goodwill amortisation and exceptional
items including impact of Hunter
Nine months to 31 December 2000
14
Net Debt Movement
m
March 2000 (4,842) Operating cashflow 1,020
Capital expenditure (769) Interest, dividends
taxation (711) Business disposals 715 December
2000 pre foreign exchange (4,587) Foreign
exchange impact (159) December 2000 (4,746)
Nine months to 31 December 2000
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Financial Summary

• Financial results, excluding Hunter impact, in
  line with management expectations
• Strong financial performance from UK businesses
• PacifiCorp financial performance, excluding
  excess power costs, ahead of management
  expectations
• PacifiCorp accretive to earnings despite Hunter
• Dividend growth of 5 being delivered

Nine months to 31 December 2000
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Agenda

• Highlights Ian Russell
• Q3 Financial Review David Nish
• US Business update Ian Russell

17
US Agenda

• Western US power market
• Management actions
• PacifiCorp Transition Plan progress

18
Wholesale Power Markets
/MWh

• Exceptionally volatileprices and demand
• Driven by
• High gas prices
• High underlying load growth
• High summer temperatures
• Lack of sufficient generation capacity
• No new plants, low hydro resources
• California situation

600
500
400
300
200
100
J
F
M
A
M
J
J
A
S
O
N
D
J
Palo Verde, Jan. 00-Jan. 01, historical prices.
19
California is Unlike PacifiCorp
California PacifiCorp Generation Divested Own
high-quality resources Fuel Diversity Gas/hydro
dependent Mainly coal Price Exposure Fully
exposed (spot) Limited exposure (balanced to
meet load) Political Outlook Unsympathetic Sympath
etic
20
Flexible Market Supply Access

• PacifiCorp 8,000 MW coal, hydro, renewable mix
• Extensive transmission reach -15,000 miles
• Operating in several markets gives regional price
  variation
• Transmission access allows ability to buy in
  low-priced areas and move power to load centres

Mid Columbia
PacifiCorpWest
Wy Gen
Pac. East
COB
Four Corners
Palo Verde
Trading markets
PacifiCorp Systems
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PacifiCorp in the Market

• Even in normal circumstances PacifiCorp trades
  throughout the WSCC to balance its own system
• Buying has increased due to
• Load demand
• Hunter outage impact
• Hydro-electric situation
• Measures in place to substantially mitigate
  exposures

22
Management actions

• Fixing Hunter
• Control credit exposure
• Demand side management
• Power cost regulatory recovery
• Add new generation capacity

23
Hunter Outage

• Electrical failure of Unit 1
• Predicted 4-6 month restoration
• Restoration now expected in 5 months - early May
• Cost of replacing power still circa 1m per day
  average over outage duration

24
Limiting Counterparty Credit Exposure

• Risk controls applied from merger
• Minimising exposure to weak counterparties
• Netting rights against trading partners when
  possible
• Making power exchanges in lieu of sales
• Less than 15m debtors exposure to troubled
  California IOUs at end of Q3

25
Demand Side Management

• 2 reduction in load (100,000 MWh)targeted for
  March 2001
• Contracting 160 MW from customer-owned generation
  - estimated benefit of 30m in Q4
• Renewing / restructuring of power contracts to
  our benefit
• Political support for reducing retail load
• Public awareness campaign
• Leadership role with government officials

26
Routes for regulatory recovery

• PacifiCorps generation is regulated
• Company entitled to earn reasonable return
• Regulators, politicians dont want another
  California
• A number of options
• General rate cases
• Interim rate cases
• Deferred accounting
• Power cost adjustment mechanism

27
Regulatory Timetable
Nov / Dec 00
Jan / Feb 01
Jul / Aug 01
Nov 01
Mar / Apr 01
May / Jun 01
Sep / Oct 01
Rate case
Oregon
Def Accntg
Utah
Rate case
Def Accntg
Idaho
Def Accntg
Wyoming
Rate case
Def Accntg
Rate case
California
F Filing H Hearing O Order Washington
may receive rate case filings
Multiple rate cases may beongoing in states at
any one time
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Oregon Filings

• Rate Case
• 160m rate case filed November 2000, including
  estimated80m of additional power costs
• Required under SB1149
• Forward looking on costs (forecast calendar 2001)
• Whats next
• Hearings scheduled for spring 2001, with order
  dueSeptember 2001
• Deferred Accounting
• Concurrent deferred accounting request November
  2000
• To recover higher power costs until rate case
  takes effect
• Whats Next
• 3 price increase expected 20 February 2001
• Additional recovery requires either interim rate
  case oragreed power cost adjustment mechanism

29
Utah Filings

• Deferred accounting request filed November 2000
• Regulators support deferral of Hunter costs
• Additional power costs recovered through rate
  case
• Whats next
• Commission approval of Hunter deferral expected
  February 2001
• Rate case filed January 2001, interim increase
  requested
• Filed for 142m, including 95m of additional
  power costs (based on calendar year 2000)
• Whats next
• Interim rate case hearing commenced January 30
• General rate case hearings early summer,with
  order in September

30
Wyoming

• Deferred accounting request filed November 2000
• Awarded December 2000
• Recovery mechanism being worked out with
  commission staff and other parties
• General rate case filed December 18, 2000
  (capped at 9m by merger order)
• Whats Next
• Filing to recover deferred costs in February 2001
• Rate case order expected May 2001

31
Idaho and Washington

• Idaho
• Deferred accounting request filed November 2000
• Commission approved request 29 January
• Whats Next
• File for recovery
• Washington
• Five year rate plan entered into May 2000
• Whats Next
• Exploring options to reopen rate plan due to
  higher costs

32
California

• Restructuring legislation (AB1890) imposed a
  price freeze until March 2002
• PGE and Edison recently received 10 price
  increase
• Whats Next
• Examining potential for an interim increase of
  the same magnitude
• Filing expected March 2001, with further filings
  later in the year
• Pursuing legislation to exempt PacifiCorp from
  price freeze

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New Generation Capacity

• Klamath Falls Joint Venture (227 MW)
• Stateline Wind Farm (300 MW)
• Wyoming Wind (50 MW)
• Gadsby Gas (Utah) (100 MW)
• New Gas in Utah (160 MW)

Adding 837 MW in 2001
34
Transition Plan Operating Cost Savings vs. 5 Year
Stretch Target
m
Net Operating Cost Savings

• Over 120 initiatives commenced
• On track for 81mof transition-related savings
  by 2000/01
• Early delivery of initiatives, including
  centralisation of procurement and introduction of
  Home Start programme formeter readers

(1998 base year)
At December 2000
Year end Transition Plan target
All values in 2000 money
35
Workforce Reduction Progressvs. 5 Year Stretch
Target
FTE
Employees

• Workforce reductionsof approximately 390from
  April
• Ahead of year 1 targetof 234 (excludes 638from
  Centralia)
• 850 identified to leave
• 5-year target of 1,600

Actual
Year end Transition Plan target
At December 2000

36
Conclusion

• Continued strong progress with US Transition Plan
• Restoration of Hunter expected in May
• Vigorously pursuing regulatory recovery of US
  excess power costs
• Good financial and operating performance from UK
  businesses
• Focus on UK energy customers