EX-99.1 2 dex991.htm PORTLAND GENERAL ELECTRIC COMPANY INVESTOR PRESENTATION DATED MAY 19-21, 2009

Exhibit 99.1

Investor Meetings

May 19-21, 2009

Copyright © 2009 Portland General Electric. All Rights Reserved.

Cautionary Statement

Information Current as of May 4, 2009

Except as expressly noted, the information in this presentation is current as of May 4, 2009 — the date on which PGE filed its Quarterly Report on Form 10-Q for the first quarter ended March 31, 2009 — and should not be relied upon as being current as of any subsequent date. PGE undertakes no duty to update the presentation, except as may be required by law.

Forward-Looking Statements

This presentation contains statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are statements of expectations, beliefs, plans, objectives, assumptions or future events or performance. Words or phrases such as “anticipates,” “believes,” “should,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” or similar expressions identify forward-looking statements. The forward-looking statements in this presentation include, but are not limited to, statements concerning long-term growth of the Oregon economy and PGE’s retail load; statements concerning the expected decline in PGE’s retail load in 2009; statements concerning changes in PGE’s energy portfolio; statements concerning estimated future capital expenditures; statements concerning future growth in rate base; statements concerning the completion dates, costs and rate treatment of the smart metering project and Phases II and III of the Biglow Canyon Wind Farm project; statements concerning the estimated cost savings from deployment of smart metering; statements concerning future financing activities; statements concerning the anticipated roll-off of margin deposits; statements concerning the recovery of costs through future rate increases; statements concerning future dividend payouts; statements concerning the outcome of various legal and regulatory proceedings; statements concerning the outcome of the renewables request for proposals; and statements concerning the future effect of Senate Bill 408.

Although PGE believes that the expectations reflected in any forward-looking statements are based on reasonable assumptions, PGE can give no assurance that its expectations will be attained. Factors that could cause actual results to differ materially from those contemplated include, among others, capital market conditions, events related to governmental policies; the outcome of legal and regulatory proceedings; the costs of compliance with environmental laws and regulations, including those that govern emissions from thermal power plants; changes in weather, hydroelectric, and energy market conditions; wholesale energy prices, which could affect the availability and cost of fuel or purchased power; rate treatment of capital projects; operational factors affecting PGE’s power generation facilities; growth and demographic patterns in PGE’s service territory; general political, economic, and financial market conditions; and other factors that might be described from time to time in PGE’s filings with the Securities and Exchange Commission.

Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, PGE undertakes no obligation to update any forward-looking statement.

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Portland General Investment Highlights

– Vertically integrated, regulated electric utility

“Pure-play” electric utility

– Attractive service territory and constructive regulatory dialogue

– 10.0% ROE on 50% equity capitalization

– Diversified, high-performing generation portfolio

– Well-managed power supply operations

Operational excellence

– High quality, well-maintained T&D system

– Highest in Western region in overall business customer satisfaction (1)

– Identified regulated capital investments of approximately $1.1 billion (2) (2009-2013) drive rate base growth

Low-risk growth plan

– Wind investments to facilitate compliance with Oregon Renewable Energy Standard

– Track record of completing projects on time and within budget

– Investment grade ratings of BBB+ / Baa2 (unsecured) Prudent financial strategy

– Target capital structure: 50% debt, 50% equity

– Focus on maintaining a strong balance sheet and adequate levels of liquidity

Stability:

Dividend Yield

Attractive total return proposition

Growth:

EPS growth

(1) PGE received the highest numerical score among electric utilities in the West region in the proprietary J.D. Power and Associates 2009 Electric Utility Business Customer Satisfaction StudySM. Study based on 15,434 interviews with U.S. business electric customers measuring 19 utilities in the West (AZ, CA, ID, NM, NV, OR, UT, WA, WY). Proprietary study results are based on experiences and perceptions of consumers/businesses/business users surveyed in April-June and September-December 2008. Your experiences may vary. Visit jdpower.com

(2) Represents total capital expenditures less depreciation and amortization.

3

Portland General Strategic Direction

Mission: To be a company our customers and communities can depend upon to provide electric service in a safe, responsible and reliable manner, with excellent customer service, at a reasonable price.

Operational Excellence

Customer satisfaction Operational efficiency Power supply, system reliability and service quality Engage and develop our people

Business Growth

Strategic system investments Encourage economic vitality Capitalize on emerging technologies

Corporate Responsibility

Listen and lead in public policy Trusted convener for customers and stakeholders Continued commitment to the Oregon community

Deliver Value to Customers and Shareholders

4

Attractive Regulated Business Profile

• Vertically integrated electric utility

– Single-state jurisdiction

– Virtually 100% regulated business providing stable earnings and cash flows

– No holding company structure

• Attractive, compact service territory with 814,058 retail customer accounts(1)

• Opportunities for investment in core utility assets

• Diversified and growing customer base

Beaver Port Westward

OREGON

WASHINGTON

Colstrip 3

(Montana)

Colstrip 4

Columbia River

Portland

Coyote Biglow Canyon Springs Boardman

T.W. Sullivan River Mill Faraday North Fork

Clackamas River

Willamette River

Salem Pleton (Madras) Round Butte

Net Utility Plant

Other CWIP $251 million $281 million Generation $1,007 million Transmission $196 million

Distribution $1,064 million

Net Utility Plant – $2,799 million(2)

(1) As of March 31, 2009. (2) Source: 2008 FERC Form 1.

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Attractive Service Territory

Weather Adjusted Load Growth (1)

(thousands of MWH)

20,000

19,000

18,000

17,000

1.4% annual growth

2003 2004 2005 2006 2007 2008

2008 Retail Revenues by Customer Group (2)

Industrial 10%

Residential Commercial 50% 40%

Total = $1.5 Billion

• Compounded annual customer growth of

1.5% and load(1) growth of 1.4% since the end of 2003

• Growth in Oregon’s economy is expected to require further investment by PGE to meet increased energy demand

– Population growth in Oregon has exceeded United States average: 1.2% vs. 1.0% from 2007-2008

– Population growth of counties in PGE’s service area has exceeded rest of state

• Load growth for 2009 is forecasted to decline by approximately 1% relative to 2008 on a weather-adjusted basis driven by:

– Reduction in residential and commercial usage partially off-set by;

– Increase in industrial loads due to expansion of solar manufacturing

(1) Adjusted for weather and certain industrial customers.

(2) No single customer accounts for more than 2% of total retail revenues.

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Constructive Regulatory Environment

• Oregon Public Utility Commission

• Governor-appointed Commission with staggered four-year terms (Lee Beyer 3/2012, Ray Baum 8/2011, John Savage 3/2009)

• Cost of Capital and Return on Equity

• 10.0% Allowed Return on Equity

• 50% Debt, 50% Equity

• Forward Test Year

• Net Variable Power Cost Recovery

• Annual Update Tariff (1)

• Power Cost Adjustment Mechanism (1)

• Decoupling

• Intended to allow recovery of fixed revenue requirements as a result of lower sales of electricity that result from customers’ energy efficiency and conservation efforts

• Effective February 1, 2009 for two-year trial period

• Renewable Energy Standard

• Standard requires that PGE meet 25 percent of its retail load from renewable sources by 2025

• Renewable Adjustment Clause (RAC)

• PGE can recover costs of renewable resources through a separate tracker

• Integrated Resource Plan

• Acknowledgement standard

• 2009 IRP - longer-term analysis to address resource decisions through 2020

(1) See Appendix

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Operational Excellence

Operational Efficiency

• Ongoing investments to improve quality of service, maintain costs and generate adequate returns

• Smart Meter Program

– Capex: $130-$135 million

– $18 million in annual operational savings projected by 2011

Customer Satisfaction

Highest customer satisfaction with business electric service in Western U.S. according to J.D. Power and Associates 2009 Electric Utility Business Customer Satisfaction Study SM (1)

Residential customer satisfaction ratings among the highest in the industry

• Highly reliable system with 92 percent plant availability in 2008

• On-going infrastructure investments to ensure high level of reliability, safety and customer satisfaction

Invested more than $775 million in the last 5 years in transmission, distribution, and existing generation

Well Maintained, High-Quality System

(1) PGE received the highest numerical score among electric utilities in the West region in the proprietary J.D. Power and Associates 2009 Electric Utility Business Customer Satisfaction StudySM. Study based on 15,434 interviews with U.S. business electric customers measuring 19 utilities in the West (AZ, CA, ID, NM, NV, OR, UT, WA, WY). Proprietary study results are based on experiences and perceptions of consumers/businesses/business users surveyed in April-June and September-December 2008. Your experiences may vary. Visit jdpower.com

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Operational Excellence

Generation Capacity (at 12/31/08)

Power Sources as % of Retail Load

Physical Capacity

% of Total Capacity

Hydro

Deschutes River Projects 298 MW 6.7%

Clackamas/Willamette

River Projects 191 4.3

Hydro Contracts 695 15.6

1,184 26.6

Natural Gas/Oil

Beaver Units 1-8 529 MW 11.9%

Coyote Springs 233 5.2

Port Westward 413 9.3

1,175 26.4

Coal

Boardman 374 MW 8.4%

Colstrip 296 6.6

670 15.0

Wind(2)

Wind Contracts 35 MW 0.1%

Biglow Canyon Phase I 46 1.0

81 1.8

Net Purchased Power

Short-/Long-term 1,345 MW 30.2%

Total 4,455 MW 100.0%

2008 Actual

Purchased Power

Gas/Oil

20% 24%

27% 29%

Coal

Hydro/Wind(1)

(1) Includes PGE owned and purchased hydro resources and PGE owned and purchased wind resources. (2) Physical capacity for wind resources provided in average megawatts.

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Business Growth

Load Growth

PGE’s long-term retail load is expected to grow consistently while selected long-term power purchase contracts expire, driving the need for additional generation capacity

Load Resource Balance Annual Average Energy(1)(2)

4,000

Retail Load and 3,500 Reserves

3,000

MWa

2,500

492 MWa 1,140 MWa 1,849 MWa (MW) Availability 2,000 218 Mwa - RFP

Average Long-term Contracts

Annual 1,500 Megawatts Generation

1,000 (Theoretical Availability, Beaver used for peaking)

500

0

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Retail Load & Resource Balance Peak Capacity(1)(3)

7,000

6,000 Retail Load with Planning and Operational Reserves

5,000

4,000 1,402 MW 2,541 MW 3,680 MW

3,000

Long-term Contracts

2,000

Generation

(Theoretical Availability, Normal Conditions)

1,000

0

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

(1) Data as of February 2009.

(2) Load forecast does not include 30 MWa of non-cost of service loads. (3) Load forecast does not include 31 MW of non-cost of service loads.

Note: Assumes 1.9% load growth through 2030 and energy supply based on plant capabilities under normal hydro and operating conditions.

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Business Growth

Capital Expenditures

($ millions)

800 $723(1) 700

(1)

600 $522 500 $455 $372 400 300 200 100 0 2007 2008 2009E 2010E

Rate Base (Average) ($ millions) 2,600 2,500 2,400 2,300 2,200 2,100 2,000 1,900 1,800 1,700 1,600

5.0 % annual growth

$2,237 $2,009 $1,766

$2,484 (2)

2002 2007 2008 2009E

• Attractive, near-term regulated growth opportunities through capital investment focused on renewable resources and core utility assets

• New capital investments funded through cash from operations and issuances of debt and equity with a targeted capital structure of 50/50

(1) Forecasted capital expenditures are preliminary and subject to change.

(2) Includes the General Rate Case average rate base of $2.278 billion plus Biglow Canyon Phase II, the Selective Water Withdrawal project, and the Smart Metering project. Excludes potential benefits from the American Recovery and Reinvestment Act of 2009.

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Business Growth

Biglow Canyon Wind Farm

• Columbia Gorge, eastern Oregon

• 450 MW total installed capacity

• Total cost approximately $1 Billion

• Biglow Canyon Phases II and III will bring PGE’s load served by renewables to approximately 11 percent (2)

Phase I Phase II Phase III

Nameplate Capacity 125 MW, 76 turbines 150 MW, 65 turbines 175 MW, 76 turbines

MW per unit 1.65 Megawatts 2.3 Megawatts 2.3 Megawatts

Cost (w/AFDC) $255 million $326 million (1) $433 million (1)

Online date December 2007 End of 2009 End of 2010

Vendor Vestas Siemens Siemens

(1) Based on March 31, 2009 10-Q .

(2) As defined by Oregon’s Renewable Energy Standard

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Business Growth

Request for Proposal (RFP) for up to 218 MWa of Renewable Resources

• Purchase power and ownership options being considered

• An independent evaluator (Accion Group) monitors the evaluation process for fairness and consistency of bid evaluation

• Wind energy heavily represented in the short list of bids

• Execution list identified with agreements expected to be completed in 2009

• With addition of 218 MWa PGE will exceed the 2015 Renewable Energy Standard requirement of 15%

Renewable Energy Standard

• Renewable resources can be tracked into rates, through an automatic adjustment clause, without a general rate case. A filing must be made to the OPUC by the sooner of the on-line date or April 1st in order to be included in rates the following January 1st. Costs are deferred from the on-line date until inclusion in rates and are then recovered through an amortization methodology.

Year Renewable Target 2011 5% 2015 15% 2020 20% 2025 25%

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Business Growth

2009 Integrated Resource Plan (IRP)

• Public planning process with OPUC acknowledgement standard

• Addresses resource decisions through 2020

• PGE to file the plan by late 2009

Expected resource requirements could include purchase power agreements, new facilities to meet base load and capacity needs, the expansion of energy efficiency programs, and additional renewable resources Potential Capital Projects:

• New energy resources

• 300-600 MW natural gas facility at Boardman (1)

• New capacity resources

• 100-200 MW natural gas facility at Port Westward

• Transmission: Southern Crossing Project

• Emissions controls at Boardman Coal Plant

• Additional renewable resources

(1) Represents an update of information since the March 31, 2009 Form 10Q.

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Prudent Financial Strategy

Target Capital Structure 50% Debt, 50% Equity

2009

Debt Issuance

• Issued $130 million of First Mortgage Bonds (FMBs) in January 2009 with interest rates of 6.5% and 6.8%

• Issued $300 million of FMBs in April at 6.1% interest rate

Equity Issuance

• Issued 12.5 million shares of common stock in March 2009 for net proceeds of $170 million

2010

Debt Issuance

• PGE anticipates issuing approximately $375 million in debt, with part of the proceeds used to redeem $186 million in maturities with the balance used for Biglow Canyon Phase III and other capital projects.

Equity Issuance

• Additional equity issuance is not expected until after 2010. Timing of additional equity needs could be impacted by the outcome of the request for proposal for up to 218 MWa of renewable resources

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Prudent Financial Strategy

Liquidity (as of 5/8/09)

($ millions)

500

400 300 200 100 0

$495

$216(1)

$72

Revolving Revolver Cash Credit Facilities Usage

• $370 million revolving credit facility

– $360 million matures in July 2013

– $10 million matures in July 2012

• $125 million 364-day revolving credit facility matures in December 2009

• Margin deposits posted by PGE as of May 8, 2009 were $354 million

– Margin deposits create a cash flow timing difference but have minimal impact on earnings

– Margin roll-off(2)

Approximately 45% in 2009 Approximately 45% in 2010

(1) Represents 100% letters of credit. On May 8, 2009, there were no draws on the revolver and no outstanding commercial paper.

(2) Assumes market prices remain unchanged and minimal new incremental transactions.

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Prudent Financial Strategy

Debt/Capitalization

60% 55% 50% 45% 40% 35% 30%

53% 52% 50% 47% 43%

(1)

2005 2006 2007 2008 2009E

Credit Ratings

Senior Secured Senior Unsecured Outlook

S&P A BBB+ Negative

Moody’s Baa1 Baa2 Positive

Manageable Near-term Debt Maturities

$186 $142 $100 $100

$0

2009 2010 2011 2012 2013

Dividend Growth

Quarterly dividend Target payout ratio

Actual Payout ratio

Target payout ratio: 60%

2008 payout ratio: 56%(2) 0 .255 2007 payout ratio: 39%.

+4.1%

+4.3% 0 .245 0.245 0.245 0.245

0.235 0.235 0.235 0.235

+4.4%

0.225 0.225 0.225 0.225

Jul-06 Oct-06 Jan-07 Apr-07 Jul-07 Oct-07 Jan-08 Apr-08 Jul-08 Oct-08 Jan-09 Apr-09 Jul-09

(1) Includes March 2009 equity issuance and January and April debt issuances of $130 million and $300 million, respectively.

(2) Based on 2008 EPS of $1.39 adjusted for Trojan Refund Order Provision of $0.32 resulting in adjusted EPS of $1.71.

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Portland General Investment Highlights

“Pure-play” electric utility

Operational excellence

Low-risk growth plan

Prudent financial strategy

Stability:

Dividend Yield

Attractive total return proposition

Growth:

EPS Growth

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Investor Relations Contact Information

William J. Valach

Director, Investor Relations 503-464-7395 William.Valach@pgn.com

Portland General Electric Company 121 S.W. Salmon Street Suite 1WTC0403 Portland, OR 97204

www.PortlandGeneral.com

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Appendix

Table of Contents

• Recent Financial Results p.21

• General Rate Case p.22

• Power Cost Adjustment Mechanism (PCAM) p.23

• Decoupling Mechanism p.24-25

• Senate Bill 408 p.26

• Regulatory, Legal and Other Considerations p.27

• Smart Grid p.28

• Boardman BART p.29-30

• American Recovery & Reinvestment Act of 2009 p.31

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Recent Financial Results

Financial Summary

Year Ended Three Months Ended

December 31, March 31,

2007 2008 2008 2009

($ in millions, except per share amounts)

Revenues $1,743 $1,745 $471 $485

Income from Operations 269 217 63 63

Net Income 145 87 28 31

EPS (basic and diluted) $2.33 $1.39 $0.44 $0.47

($ earnings per diluted share)

Full-year Year-to-Date (Q1)

2007 2008

• Boardman deferral (+$0.26) • Non-qualified benefit plan assets (-$0.04)

• California settlement (+$0.06) • Senate Bill 408 (-$0.02)

• Non-qualified benefit plan assets (+.05)

• Senate Bill 408 (+$0.18)

2008 2009

• Trojan Refund Order Provision (-$0.32) • Non-qualified benefit plan assets (-$0.02)

• Non-qualified benefit plan assets (-$0.19) • Storm Costs (-$0.01)

• Beaver oil sale (+$0.10)

• Senate Bill 408 (-$0.10)

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2009 General Rate Case Outcome

Outcome of Oregon Public Utility Commission (OPUC) final order regarding PGE’s rate case:

Regulatory Structure

• Allowed ROE: 10.0% (1)

• Equity capitalization: 50%

• Debt capitalization: 50%

• Return on rate base: 8.28%

• Methodology for modeling net variable power cost (NVPC)

Rate Base and Revenue

• Average rate base: $2.278 billion(2)

• Rate increase: $121 million

– % increase: 7.3%(3)

– NVPC: $95.4 million

– O&M, A&G and other: $25.6 million

Commentary

• The increase became effective January 1, 2009

• The OPUC accepted PGE’s recommendation for a decoupling mechanism for a period of two-years. On January 30, 2009 PGE filed with the OPUC for deferred accounting of revenues associated with the decoupling mechanism. On March 24, 2009 the Citizen’s Utility Board (CUB) filed with the OPUC seeking reconsideration of decoupling decision

(1) Reduction from 10.1% to 10.0% as a condition of decoupling.

(2) Excludes smart metering, selective water withdrawal and Phases II & III of the Biglow Canyon Wind Farm. Average rate base including smart metering, selective water withdrawal and Phase II of Biglow Canyon Wind Farm is $2.484 billion.

(3) Certain customer credits from the 2007 Power Cost Adjustment Mechanism effectively reduces the average price increase from 7.3% to 5.6%.

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Recovery of Power Costs

Annual Power Cost Update Tariff

• Annual reset of rates based on forecast of net variable power costs (NVPC) for the coming year. Following OPUC approval, new prices go into effect on or around January 1 of the following year.

Power Cost Adjustment Mechanism (PCAM)

Power Cost Sharing

Customer Surcharge

90/10 Sharing

150 Bps $30 million(1) of ROE

Baseline

NVPC (1) 75 Bps

($15) million of ROE

90/10 Sharing

Customer Refund

Earnings Test

Customer Surcharge

9.0%

Equity 100 Bps on 10.0% 100 Bps Return 11.0%

Customer Refund

• PGE absorbs 100% of the costs/benefits within the deadband, and amounts above or below the deadband are shared 90% with customers and 10% with PGE.

• An annual earnings test is applied as part of the PCAM.

• Customer surcharge occurs to the extent it results in PGE’s actual ROE being no greater than 9.0%

• Customer refund occurs to the extent it results in PGE’s actual ROE being no less than 11.0%

(1) Deadband for 2009.

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Decoupling Mechanism

• The decoupling mechanism is intended to allow recovery of reduced earnings resulting from a reduction in sales of electricity resulting from customers’ energy efficiency and conservation efforts

– A condition of the decoupling mechanism is a reduction in the Company’s allowed ROE from

10.1% to 10.0% which reflects the OPUC’s view of a reduction in Company risk. The ROE refund is estimated at approximately $1.9 million annually

• Implemented mechanism (SNA) under for a new residential two-year and tariff small that non includes -residential a Sales customers Normalization (£30 kW) Adjustment and a Lost Revenue Recovery mechanism (LRR), for large non-residential customers (between 31 kW and 1 MWa)

– The SNA is based on the difference between actual, weather-adjusted usage per customer and that projected in PGE’s recent general rate case

– The LRR is based on the difference between actual energy-efficiency savings (as reported by the ETO) and those incorporated in the applicable load forecast

On January 31, 2009, PGE filed an application with the OPUC to defer, for later rate-making treatment, potential revenues associated with the new decoupling mechanism as well as revenues associated with an ROE refund

Mechanism effective February 1, 2009

On March 24, 2009 CUB filed with the OPUC seeking reconsideration of decoupling decision

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Decoupling Mechanism

Simplified Decoupling Example Assumptions:

Residential customer Monthly Kwh usage: 1,000 Cost per Kwh: $0.10

Weather adjusted decrease in monthly usage: 10%

PGE cost structure: 50% power costs and 50% all other costs

Analysis:

Base monthly bill: 1,000 x $0.10 = $100 Revised monthly bill due to energy efficiency and/or conservation: 900 x $0.10 = $ 90 Reduction in revenue from customer = $ 10

PGE cost structure of lost revenue: $5 in power costs $5 in all other costs (fixed costs)

Financial impact on PGE:

Power costs: Approximately $0 earnings impact on PGE, assuming power sold on the market at PGE average cost in prices All other costs: Approximately $0 earnings impact due to $5 booked as a regulatory asset for future recovery from customers (through the decoupling mechanism)

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Oregon Senate Bill 408

• Beginning January 1, 2006, SB 408 requires the OPUC to track estimated income taxes collected by Oregon utilities in rates and compare this amount to adjusted taxes paid to taxing authorities by the utility or corporate consolidated group. The OPUC may establish deferral accounts to capture the difference

• SB 408 requires an annual rate adjustment if difference between taxes authorized to be collected by the utility and taxes paid by the utility to taxing authorities exceed $100,000

• Report for prior calendar year is filed in October with the refund or collection beginning in June of the following year. For example:

– The 2008 report of taxes paid will be filed in October 2009. New tariff goes into effect June 2010, if necessary

• Primary issue for PGE is the so called “double whammy” effect, due to the OPUC adopting a fixed reference point for margins and effective tax rates. The double whammy can result in unusual outcomes and increased financial volatility in certain situations. The OPUC stated in the final order that it will be responsive to concerns related to the consequences of the double whammy problem, and may address those concerns in other regulatory proceedings

• Historical/expected outcomes:

– 2006: Customer refund of approximately $37.2 million plus accrued interest

– 2007: Customer collection of $14.7 million plus accrued interest

– 2008: Expected customer refund of approximately $10 million plus accrued interest

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Regulatory, Legal and Other Considerations

Selective Water Withdrawal Project

• Pelton/Round Butte project to restore fish passage on the upper Deschutes River

• Capital cost (PGE share) approximately $80 million (including AFDC)

• On April 14, 2009 PGE filed a motion to suspend procedure schedule due to delay in construction

• OPUC docket: UE 204

Colstrip Coal Plant

• PGE has a 20% ownership interest in Units 3 and 4 of the Colstrip coal plant

• During the 2009 scheduled maintenance outage of unit 4, two rotors were found to be damaged

• The outage will be extended 8 to 10 weeks to repair the rotors

• Repair costs have not yet been determined but replacement power costs are estimated at $2 million to $3 million

Boardman Coal Plant Deferral

• Request with the OPUC to amortize a $26.4 million deferral of replacement power costs, plus accrued interest

($8.5 million as of March 31, 2009) associated with the forced outage of Boardman from November 18, 2005 through February 5, 2006

• Request subject to prudency review and regulated earnings test

• OPUC docket: UE 196

Trojan Nuclear Plant: Recovery of Return on Investment

• OPUC Proceedings – Dockets: DR 10, UE 88, UM 989

– Begun refund notification/application process and expect refunding to be complete by end of November.

• Class Action Proceedings

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Smart Grid

• Smart Meters

• Provides two-way communications with residential and commercial customers

• Vendor: Sensus Metering Systems

• Technology: FlexNet radio frequency technology

• Deployment: 850,000 residential and commercial customer meters

• Estimated cost: $130 million - $135 million

• Estimated completion: 2010

• OPUC approved limited term tariff: June 1, 2008 through December 31, 2010. After 2010 the projects costs, net of savings, would be permanently incorporated into rates in a future rate case

• Distribution System

• Pursuing direct load control programs

• Optimizing distribution system through advanced technology

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Boardman BART Update

• Best Available Retrofit Technology (BART) for compliance with EPA Regional Haze Rule

• In December 2008, the Department of Environmental Quality (DEQ) issued a proposed plan that would require the installation of controls in three phases:

Phase 1: Installation of low NOx burners, completion by 2011

Phase 2: Installation of semi-dry scrubber and bag house to address mercury and sulfur dioxide removal, completion by 2014

Phase 3: Installation of Selective Catalytic Reduction for additional NOx controls, completion by 2017 DEQ proposes that Phases 1 and 2 would meet federal BART requirements. Phase 3 is recommended by the DEQ to make reasonable progress towards haze emission reduction goals.

PGE cost estimate for Phases 1, 2 and 3 for the DEQ plan: $575 to $640 million (1)

• PGE proposed an alternative in comments that would allow for decision points along the DEQ timeline to provide flexibility to make the most cost-effective decision on future controls at those points.

• The comment and public input period for the DEQ proposal has closed

• Schedule:

– Oregon EQC decision on BART June 2009

– EPA approval Early 2010

29 (1) 100% of estimated cost in nominal dollars and excludes AFDC.

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Decision Point Proposal

PGE Alternative Boardman BART/Reasonable Progress Proposal

Control Operate Operate Mercury through 2020 through 2029

No

No

Yes Yes Operate

2011 2012 2014 2015 2017 Full Plant

Life

Decision Point On SO2 Controls

Decision Point On SCR**

Install Low NOx Burners Reduction: 5,805 tons NOx/yr

Install SO2 & mercury Controls Reduction: 12,665 tons SO2/yr 165 lbs mercury/yr

Install Selective Catalytic Reduction Reduction: 4,222 tons NOx/yr

**Assumes that Selective Catalytic Reduction (SCR) is required under Reasonable Progress

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American Recovery & Reinvestment Act of 2009

• PGE is evaluating the impact and certain benefits that may be available under the American Recovery and Reinvestment Act of 2009 (the Act)

• The Act provides a number of enhanced tax benefits, many of which are highly favorable to renewable energy projects such as PGE’s Biglow Canyon windfarm:

• For windfarms the Production Tax Credit (PTC) was extended from 2009 through 2012

• In lieu of the PTC, the company may elect either:

• Investment Tax Credit (ITC) – upfront 30% tax credit

• Treasury Department Grants (1) – Cash payment in lieu of claiming PTC or ITC

• Based on PGE’s preliminary assessment of current provisions of the Act, the Company believes that it may be entitled to qualify for the Treasury Department grant option in amounts ranging from:

• $60 million to $90 million for Biglow Canyon Phase II in 2009

• $80 million to $110 million for Biglow Canyon Phase III in 2010

• The availability of any such grants under the Act and the Company’s final determination of whether to seek such grants or other benefits under the Act are subject to various other factors. Accordingly, there is no assurance that the Company will either seek or receive any grants or other benefits under the Act.

(1) For qualifying renewable energy facilities placed in service in either 2009 or 2010, or for qualifying renewable energy facilities on which construction commenced during 2009 or 2010 and that are placed in service after 2010 but prior to 2013.

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Portland General Electric

32