1

BPA Financial Choices Closeout Presentation

for Fitch Ratings

November 26, 2002

2

Regional Values

• We asked the region about values and trade-offs

– The region still values:

• BPA paying Treasury on time

• Meeting our ESA and Northwest Power Act fish and wildlife performance obligations

• Delivering value to the region in the form of public benefits programs and low rates

– However, what we’ve heard from customers is that the pendulum has swung in terms of the focus/underlying goal:

• In the early 2000s, the region wanted BPA to emphasize reliability over cost-minimization

• Now and for the foreseeable future, our customers are most concerned about the costs and the impact of near-term rates in the context of the depressed regional economy

3

Net Revenue Gap

Main Drivers:

1. Further reduction in market prices, mostly in the FY02 period

2. Updated hydro energy forecast

3. Uncertainty in payment of liquidated damages by DSIs

Prior to any BPA expense reductions, the Power Business Line’s financial situation has eroded since May 2002

$(3,000)

$(2,500)

$(2,000)

$(1,500)

$(1,000)

$(500)

$-

$500

$1,000

$1,500

0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95%

Probability Distribution

$ in

Mill

ions

May 2002 FY02-06

Forecasted Net Revenue gap = ($860 M)

October 2002 FY02-06 Forecasted Net Revenue gap = ($1,200

M)

4

Net Secondary Revenue

• The net revenue we now expect to receive for our secondary energy is still significantly higher than what we received historically

• Since the higher net revenue from secondary sales is embedded in the current net revenue forecast, this makes our financial condition heavily dependent on the price of energy and water conditions

Trading Floor Net Revenue(Historical and Projected)

$-

$100.0

$200.0

$300.0

$400.0

$500.0

$600.0

$700.0

$800.0

FY 1996 FY 1997 FY 1998 FY 1999 FY 2000 FY 2001 FY 2002 FY 2003 FY 2004 FY 2005 FY 2006-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

Revenue Amount

ForecastedHistorical

$ in

Mil

lion

s

aMW

*FY2001: No net surplus sales due to drought.

5

Actions BPA is Taking to Manage the Gap

• The financial choices process proposed 5 different ways to help solve our financial problem.

• Approach #1 – Manage thru Rates Only • Approach #2 - Cut Costs & Increase Efficiencies (no rate

impact)• Approach #3 – Increase Financial Risk to Treasury (No SN

CRAC)• Approach #4 – Defer Costs & Push Problem to Future• Approach #5 - One-Time Adjustment of Rates through SN

CRAC

• BPA is looking to adopt a hybrid of these choices in managing the financial gap. These include:

• Reducing FY03-06 expenses by $220 M (Approach #2)• Deferring $72 M in expenses to the FY07–11 period

(Approach #4)• Purchasing surety bonds to free up $56 M of ENW reserve

funds, which is similar to an expense deferral (Approach #4)

• Engaging outside parties to try and further reduce costs (Approach #2)

• Reassess need for SN CRAC after January 1, 2003

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(10)

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110

Aug

men

tati

on (

not

incl

udin

g IO

UB

enef

its)

IOU

Ben

efit

s

Fis

h &

Wil

dlif

e

Col

umbi

aG

ener

atin

g S

tati

on*

Inte

rnal

Ope

rati

ngC

osts

*

Cor

ps/R

ecla

mat

ion*

Ext

erna

l E

xpen

ses

Pen

sion

Cos

ts

Ren

ewab

les*

Con

serv

atio

n/E

E*

Ch

ange

fro

m F

Y01

($M

)

Average Annual Expense Reduction

Average Annual Deferral

Remaining FY01 vs. FY03-06 Delta

FY01 vs. FY03-06 Program Spending Reductions

• PBL Internal Operating Costs have been reduced to below FY01 actual levels

PBL Internal Operations includes power portion of Shared Services/Corporate G&A, Power Business Operations, PBL Efficiencies and Generation Development & Coordination.

External Expenses includes Telemetering & Equipment for GTA service, Trojan O&M, GTA Wheeling, Colville Settlement and Long-Term Generating Projects.

Columbia Generating Station is average of FY00/01 to account for refueling and non-refueling years.

F&W Operations: The difference between the 2000 BiOp versus the 1998 BiOp of 59 aMW * $35/MWh market price.

Conservation/EE does not include interest or capital expenses.

Programs with (*) includes offsetting revenues; excludes Planned Net Revenues for Risk (PNRR).

Average Annual DeltaNovember 2002 Update$505 $331

0

100

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400

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600

FY01 Actual Level

7

We Have Significantly Reduced Expenses & More Expense Reductions Are Possible

• Current achievements: $348M in expense reductions, expense deferrals and cash increases over FY03-06– $220M in expense reductions– $72M in expense deferrals– $56M in cash increases

• BPA internal expenses for 2003-2006 brought down to 2001 actual spending levels, saving $136M– Cuts in BPA staffing, travel, training, contract labor– Cuts involve risk to customer service, IT systems, succession

planning for aging workforce, and energy efficiency and technology initiatives

– These risks are acceptable

• Corps, Reclamation, Energy NW, Conservation, and Renewable costs reduced $84M– Deferred IOU expenses from FY03 to FY04-06: $55M

8

• Deferred expenses into next rate period: $72M– Energy Northwest – Fuel strategy ($37M)– Energy Northwest – Condenser tube replacement ($35M)

• Surety bonds to back-up Energy Northwest debt to free up cash this year: $56M

• Areas still in play (could be up to $600M)– Fish & wildlife program and operation expenses– Residential and small farm benefits to IOUs– Enron contracts portfolio settlement– Other expense reductions from Energy Northwest– Additional surety bonds to free-up cash for FY04-05

We Have Deferred Some Expenses & Are Planning To Free Up Some Cash

9

FY03-06 Expense Reductions & Deferrals

Internal Operating Costs on previous graph.

Not portrayed on previous graph.

Columbia Generating Station expense deferral on previous graph.

Respective amounts portrayed in Corps/Reclamation and Columbia Generating Station bars on previous graph.

Not portrayed on previous graph.

1 Reductions from Financial Choices package.2 These numbers do not include revenue changes and also do not reflect the total PBL budget.3 Average reduction per year as shown on previous graph. Actual reductions may be shaped from year to year.4 $2M of interest expense reduction not shown on graph.5 Highly Probable case assumes deferral will be credited towards future SN CRAC. Use of amount of credit still under discussion.

10

FY03-06 Expense Reductions & Deferrals

Internal Operating Costs on previous graph.

Not portrayed on previous graph.

Columbia Generating Station expense deferral on previous graph.

Respective amounts portrayed in Corps/Reclamation and Columbia Generating Station bars on previous graph.

Not portrayed on previous graph.

11

$(3,000)

$(2,500)

$(2,000)

$(1,500)

$(1,000)

$(500)

$-

$500

$1,000

$1,500

$2,000

0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95%

Probablity Distribution

$ i

n M

illi

on

s

Closing the PBL Net Revenue Gap• Combined NR distribution 1) before actions, 2) with highly probable

reductions and 3) with highly probable and “low”still under discussion reductions

• Includes a maximum FB CRAC in FY04-06 in highly probable reductions net revenue and highly probable and “low” still under discussion net revenues

Before Actions Net Revenue = ($1.2 B)

With highly probable actions net revenue =

($575 M)

With highly probable and “low” still under discussion

actions net revenue = ($370 M)

12

LB CRAC & FB CRAC – Impact on Rates

0%

10%

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60%

FY02 FY03a FY03b FY04 FY05 FY06

BPA Fiscal Year

Incr

ease

ove

r B

ase

Rat

es

LBCRAC increases

approximately 8% over May Base Rates in

April 2003

$22.3

$31.8

The annual LB CRACs for FY04-06 are expected to exhibit the same seasonality shown in the LB CRACs for FY03a & FY03b.

We expect that the FBCRAC triggers to its maximum over FY04-06 resulting in roughly

flat rates: $333M

13

0%

10%

20%

30%

40%

50%

60%

FY02 FY03 FY04 FY05 FY06

SNCRAC – Impact on Rates

With only the expense reductions

& expense deferrals that are highly probable

With expense reductions &

expense deferrals that are certain &

low - high still under discussion

LB CRAC

LB CRAC

LB CRAC

LB CRAC

LB CRAC

FB CRAC

FB CRAC

FB CRAC

FB CRAC

Gap w/High

*Assumes secondary revenue achieved at forecasted levels for FY03-06.

Drop in LB CRAC due to IOU/Public litigation

settlement: $200M

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FY02 FY03 FY04 FY05 FY06

BPA Fiscal Year

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ease

ove

r B

ase

Rat

es

LB CRAC

LB CRAC

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LB CRAC

LB CRAC

FB CRAC

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FB CRAC

FB CRAC

SN CRAC

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SN CRAC

Gap w/HighGap

w/High

Gap w/LowGap

w/LowGap

w/Low

14

SN CRAC – Impact on Rates

• Under our rate schedule provisions, the safety-net cost recovery adjustment clause (SN CRAC) will “trigger” if the administrator determines 1) BPA forecasts a 50 percent or greater probability that it will nonetheless miss its next payment to Treasury or other creditor, or 2) BPA has missed a payment to Treasury or has satisfied its obligation to Treasury but has missed a payment to any other creditor– The current outlook of our ability to pay Treasury in FY2003 has

dropped from the level targeted in our power rate case, but for now is above the level for triggering a safety net CRAC

– The probability of paying Treasury is very sensitive to water and market conditions and could go up or down

– We are seeking to improve our Treasury payment probability, but unless there is a dramatic increase in net secondary revenue, it is unlikely to get back to historic levels during the rate period

15

Conclusions…

• We are not proceeding with triggering the SNCRAC rate process right now– Whether or not we trigger the SNCRAC is heavily dependent on …

• Revenue we receive for our secondary energy which is exposed to market prices and water conditions

• Additional expense reductions

– Fish & wildlife program expenses

– Benefits to residential and small farm consumers of IOUs

– Contract renegotiations

– Other additional expense reductions from Energy Northwest• Level of cost deferrals

• We will reassess whether we will trigger the SNCRAC process after January 1, 2003 – If our hydro condition erodes by 15% this year, our net revenue could

decline $150-$200 M

– The variability in market prices of + 40% will affect our net revenue by $250-300 M