EX-99.1 2 exhibit991.htm INVESTOR PRESENTATION
Investor Presentation August 2012 1 Exhibit 99.1

Cautionary Statement Information Current as of August 7, 2012 Except as expressly noted, the information in this presentation is current as of August 7, 2012 — the date on which PGE filed its Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012 — 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 Statements in this presentation that relate to future plans, objectives, expectations, performance, events and the like may constitute “forward-looking statements” 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 include statements regarding earnings guidance, statements regarding future load, hydro conditions and operating and maintenance costs; statements concerning implementation of the Company’s Integrated Resource Plan and related future capital expenditures, statements concerning future compliance with regulations limiting emissions from generation facilities and the costs to achieve such compliance; statements regarding the outcome of any legal or regulatory proceeding; as well as other statements containing words such as “anticipates,” “believes,” “intends,” “estimates,” “promises,” “expects,” “should,” “conditioned upon,” and similar expressions. Investors are cautioned that any such forward-looking statements are subject to risks and uncertainties, including the reductions in demand for electricity and the sale of excess energy during periods of low wholesale market prices; operational risks relating to the Company’s generation facilities, including hydro conditions, wind conditions, disruption of fuel supply, and unscheduled plant outages, which may result in unanticipated operating, maintenance and repair costs, as well as replacement power costs; the costs of compliance with environmental laws and regulations, including those that govern emissions from thermal power plants; changes in weather, hydroelectric and energy markets conditions, which could affect the availability and cost of purchased power and fuel; changes in capital market conditions, which could affect the availability and cost of capital and result in delay or cancellation of capital projects; problems or delays in completing capital projects, resulting in the abandonment of such projects or the failure to complete such projects on schedule or within budget, which could result in the Company’s inability to recover project costs; the outcome of various legal and regulatory proceedings; and general economic and financial market conditions. As a result, actual results may differ materially from those projected in the forward-looking statements. All forward- looking statements included in this presentation are based on information available to the Company on the date hereof and such statements speak only as of the date hereof. The Company assumes no obligation to update any such forward-looking statement. Prospective investors should also review the risks and uncertainties listed in the Company’s most recent Annual Report on Form 10-K and the Company’s reports on Forms 8-K and 10-Q filed with the United States Securities and Exchange Commission, including Management’s Discussion and Analysis of Financial Condition and Results of Operations and the risks described therein from time to time. 2

PGE Value Drivers 3 • Solid utility operations • Strong financial position • Growth in service territory • Clear focus, 100% regulated utility • Net-short utility, need for new generation • Multiple opportunities for rate base growth • Progressive environmental position

P G E I N V E S T M E N T T H E S I S Strong Platform. Positioned for Sustained Growth. The Company The Strengths The Growth 4

 Vertically integrated – generation, transmission and distribution  Market cap >$2B  Service area in northwest Oregon – includes Portland and Salem – 828,000 customers(1) – 50% of Oregonians depend on PGE for electricity – 75% of Oregon’s commercial and industrial activity Gas Hydro Coal Wind Service territory PGE At A Glance (1) As of June 30, 2012 Beaver Port Westward WASHINGTON OREGON Portland Faraday Oak Grove I-5 26 84 Columbia River Sandy River Salem North Fork River Mill T.W. Sullivan 5 Colstrip 3 & 4 Montana Coyote Springs Biglow Canyon Boardman Eastern Oregon Pelton Round Butte Madras Oregon

Attractive, Growing Service Territory 18.5 18.6 18.8 2010 2011 2012E • Long term forecast >1% annually through 2030 1) Population growth based on data from The Oregon Office of Economic Analysis (OEA) 2) Adjusted for weather and certain industrial customers; 2012E assumes 1% load growth over 2011 levels 6 Demographics Industrial Growth • Growth in high-tech & manufacturing – Intel’s D1X facility – Data centers – Parts and other manufacturing • Construction employment growing compared to a decline for the US • Population growth of 1-1.2% annually through 2020(1) Economy continues to improve Continued in-migration Retail Load Growth(2) (Million MWhs)

History of Successful Execution of Capital Projects Recent Capital Projects Average Rate Base $1,939 $2,381 $2,425 $2,863 $3,152 2007 2008 2009 2010 2011  Biglow Canyon Wind Farm (2007-2010) ‒ Three phase build-out; $960 million  Smart Meters (2008-2010) ‒ 825,000 meters installed; $145 million  Selective Water Withdrawal (2009) ‒ Innovative fish migration facility; $85 million (2)  Port Westward Gas Plant (2007) ‒ 410 MW CCGT; $280 million ($M) 1) 2011 rate base amount represents the average rate base included in PGE's 2011 General Rate Case 2) Represents PGE’s 67% share of the facility 7 (1)

P G E T O D A Y Ready for the Next Growth Phase 2006 – 2010 2011 – 2012 2013+ Grew business and built solid platform Transition – preparing for next growth phase Strong, sustainable growth 8

The Company P G E I N V E S T M E N T T H E S I S Strong Platform. Positioned for Sustained Growth. The Strengths The Growth 9

Key Strengths 1 Diversified customer base and generation portfolio 2 High quality utility operations 3 High customer satisfaction rate 4 Solid performance record 5 Strong balance sheet and financial resources 10

1. Diversified Customer Base and Generation Portfolio Power Sources as a Percent of Retail Load Per the 2012 AUT(1) Residential 50% Commercial 37% Industrial 13% Retail Revenues by Customer (2011) Total = $1.7B 1) Annual Update Tariff Hydro and wind/solar include PGE owned and contracted resources; purchased power includes long-term contracts 11 Purchased Power 42% Hydro & Wind 29% Coal 19% Gas 10% Purchased Power 26% Hydro 22% Wind & Solar 9% Coal 26% Natural Gas 17% Total = 2,217 MWa

2. High Quality Utility Operations  Highly reliable generation portfolio with 93% availability in 2011  Ongoing T&D investment to ensure high levels of reliability and customer satisfaction  Strong power supply operations to stabilize and optimize power costs  Progressive approach to reduce coal generation – Boardman 2020 Plan  Continued investment in technology to improve service and reduce costs Effective Utility Operations 12

Top Decile 3. High Customer Satisfaction No. 2 In the West for general business satisfaction Investor-owned utility in the nation for residential customer satisfaction Nationally among large key customers for satisfaction JD Power & Associates JD Power & Associates TQS Research, Inc. No. 1 All customer satisfaction and reliability measures consistently top quartile 13

4. Solid Earnings 8.0% 9.0% 2010 2011 2012E $125 $147 $140- 151(1) 2010 2011 2012E ROE Net Income ($M) $1.66 $1.95 $1.85- 2.00(1) 2010 2011 2012E EPS (Diluted) Reduced gap between actual ROE and allowed ROE of 10% 14 1) Based on guidance range, as most recently reaffirmed on August 7, 2012 8.2- 9.0%(1)

4. Continuous Dividend Growth $0.92 $0.96 $1.00 $1.03 $1.05 $1.07 2007 2008 2009 2010 2011 2012 3.1% CAGR Target Payout Ratio of 50 to 70% Note: Represents annual dividends paid 15

5. Strong Balance Sheet and Financial Resources $660 $115 $74 Total Credit Facilities Letters of Credit Cash  Investment grade ratings of BBB and Baa2  Manageable debt maturities – weighted average 15.5 years  Target capital structure of 50% debt, 50% equity  2012 capital expenditures of $320M, funded from operations Financial Resources Revolving Credit Facilities (1) (in millions) 16 1) All values as of 7/1/2012

P G E I N V E S T M E N T T H E S I S Strong Platform. Positioned for Sustained Growth. The Company The Strengths The Growth 17

0 500 1000 1500 2000 2500 3000 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Future Generation Need 2015 shortfall 513 MWa MWa Long-Term Contracts PGE Generation 1) Load-Resource Forecast Data from 2011 IRP Update, filed with the OPUC on 11/23/2011; shortfall is net of energy efficiency Load-Resource Forecast(1) - Energy Opportunity to grow rate base Retail load Demand Exceeds Generation Resources 18

Potential Opportunities for Rate Base Growth $3.1B (1) Average Rate Base 2011 2016-2017 1 2 4 New peaking capacity New base load energy Cascade Crossing 3 5 New renewable energy 19 1) Rate base growth dependent on outcome of RFP processes; PGE is committed to move forward with the least cost, least risk option for customers Potential to add $2B to rate base

1. New Peaking Capacity Resource Requirement  200 MW year-round flexible resource  200 MW bi-seasonal (winter and summer) peaker  150 MW winter-only peaker Specifications  Bidders can submit a PPA, build own transfer or asset purchase agreement of an existing facility  Port Westward 2 submitted as PGE’s benchmark bid  Bidders can also submit projects on PGE’s benchmark site ‒ Project will be owned and operated by PGE and must be built to PGE’s specifications June 8 2012 August 1 2012 August 8 2012 Q4 2012 Q1 2013 2015 RFP Document issued to market PGE’s benchmark bid submitted All other bids submitted Identify initial and final short list Final decision and closing report issued to OPUC Earliest in-service date for new construction Timeline 20

2. New Base Load Energy Resource Requirement  300-500 MW base load energy resource Specifications  Bidders can submit a PPA, build own transfer or asset purchase agreement of an existing facility  Carty I submitted as PGE’s benchmark bid  Bidders can also submit projects on PGE’s benchmark site ‒ Project will be owned and operated by PGE and must be built to PGE’s specifications June 8 2012 August 1 2012 August 8 2012 Q4 2012 Q1 2013 2016 RFP Document issued to market PGE’s benchmark bid submitted All other bids submitted Identify initial and final short list Final decision and closing report issued to OPUC Earliest in-service date for new construction Timeline 21

3. New Renewable Energy Resource Requirement  100 MWa resource(1) Specifications  To meet Oregon’s Renewable Energy Standard of 15% by 2015 – wind, solar, biomass or other  Bidders can submit a PPA, build own transfer or asset purchase agreement of an existing facility  Benchmark bid will be submitted by PGE 1) If the renewable resource is a wind project, the name plate MW size would be approximately 300 MW using a 30% capacity factor July 25, 2012 Q3 2012 Q3-Q4 2012 Q4 2012 Q4 2012 - Q1 2013 2015 Filed official draft RFP with OPUC Receive RFP approval from OPUC Issue RFP to bidders; final bids due two months later PGE submits benchmark bid Final short list and decision Earliest in-service date if new construction Timeline 22

Requirement  500 kV line, approximately 215 miles Specifications  Path from Eastern Oregon to Salem, south of Portland  Connect Boardman, Coyote Springs, and potential new projects to service territory  Provide transmission access for new potential wind resources  Improve regional grid reliability  Capital investment of $800M to $1B Next Steps  Ongoing negotiations with: – BPA on collaboratively improving the regional transmission system – PacifiCorp on their participation in the project – Confederated Tribes of the Warm Springs on easements  Multiple permitting processes underway  Assuming all necessary approvals, construction to begin in 2014  Operational late 2016 or early 2017 4. Cascade Crossing Transmission Project 23

Potential Capital Projects Timeline 24 (in millions) 2012 2013 2014 2015 2016 2017 Capacity Resource $250-$350 Energy Resource $550-$700 Renewable Resource $700-$850 Cascade Crossing $800-$1,000 Base Capital Spending(1) $325 $300 $275 $275 $350 $375 1) Includes ongoing capital expenditures, hydro relicensing, and Boardman emissions controls Amounts exclude AFUDC debt and equity. • Capacity, energy and renewable forecast assumes self-build benchmark projects are selected; actual timing and costs are contingent on outcome of PGE’s competitive RFP processes • Cascade Crossing project is preliminary; progress contingent on a successful agreement with BPA and acquiring all necessary approvals, permits and easements

Portland General Electric 5-Year Outlook  Strong balance sheet  Continued EPS growth  Solid growth in customer demand 25  Potential rate base growth of $2B

S U M M A R Y Strong Platform. Positioned for Sustained Growth. The Growth Multiple growth opportunities • Capacity, energy, renewables and transmission • >$2B potential rate base growth 26 The Strengths Solid platform • Operational excellence, high customer satisfaction and strong financial position The Company 100% regulated electric utility • Attractive service territory • Constructive regulatory environment

Portland General Electric Appendices 27

Appendices 1. Financials 2. Resource planning 3. Regulatory environment 4. Business initiatives – details 28

YTD 2012 Financial Results 29 Net Income Earnings per Share (in millions) 2011 2012 2011 2012 Q1 $69 $49 $0.92 $0.65 Q2 $22 $26 $0.29 $0.34 YTD $91 $75 $1.21 $0.99 $463 $462 $390 $394 2011 2012 Q2 Q1 $853 $856 YTD Q2 Retail Revenues (in millions) Q2 2012 0.5% YTD Q2 2012 1.0% Full Year 2012 Forecast 1.0% Weather Adjusted Load Growth (excluding two large paper manufacturers)

Appendices 1. Financials 2. Resource planning 3. Regulatory environment 4. Business initiatives – details 30

1) Capacity of a given plant represents the megawatts the plant is capable of generating under normal operating conditions, net of electricity used in the operation of the plant 2) Wind generation from contracts and Biglow Canyon is expressed in average megawatts; Biglow’s capacity reflects the weighted average capacity factor for all three phases of the project Resource Mix Resource Capacity (at 12/31/11)(1) Capacity % of Total Capacity Hydro Deschutes River Projects 298 MW 7.1% Clackamas/Willamette River Projects 191 4.6 Hydro Contracts 485 11.6 974 23.3 Natural Gas/Oil Beaver Units 1-8 516 MW 12.4% Coyote Springs 246 5.9 Port Westward 410 9.8 1,172 28.1 Coal Boardman 374 MW 9.0% Colstrip 296 7.1 670 16.1 Wind(2) Wind Contracts 44 MWa 1.1% Biglow Canyon 159 3.8 203 4.9 Purchased Power 1,149 27.6% Total 4,168 MW 100.0% 31 Purchased Power 42% Hydro & Wind 29% Coal 19% Gas 10% Power Sources as a Percent of Retail Load Per the 2012 AUT Purchased Power 42% Hydro & Wind 29% Coal 19% Gas 10% Purchased Power 26% Hydro 22% Wind & Solar 9% Coal 26% Natural Gas 17% Total = 2,217 MWa

Business Growth: Integrated Resource Plan Integrated Resource Planning Process  Under OPUC guidelines, PGE is required to file an Integrated Resource Plan within two years of acknowledgment of the previous plan  The IRP requires that the primary goal must be the selection of a portfolio of resources with the best combination of expected costs and associated risks and uncertainties for the utility and its customers  OPUC acknowledgement of the IRP is standard. Acknowledgement is not approval for rate-making purposes, but the Commission has stated that it will give “considerable weight” to utility actions that are consistent with the acknowledged IRP 2009 Integrated Resource Plan  In November 2010, PGE received acknowledgement of the IRP originally filed in November 2009  PGE filed a 2011 Integrated Resource Plan Update on November 23, 2011 – Includes an update to the 2009 Action Plan implementation activities – Examines new projections for future customer demand and the resulting portfolio balance – Addresses anticipated differences in timing for the acquisition of new resources identified in the 2009 Action Plan – Includes discussions on Demand Response, the Renewable Energy Standard, Boardman, Cascade Crossing and Wind Integration – Since PGE is not proposing changes to the IRP Action Plan, acknowledgement by the OPUC of the 2011 IRP Update is not necessary Next Integrated Resource Plan  The OPUC approved PGE’s plan to file an IRP update in November 2012 and a new IRP in November 2013 32

Energy Load-Resource Balance 0 500 1000 1500 2000 2500 3000 3500 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 A n n u al A v e rage A v ai labili ty ( M W a ) Long-term Contracts 632 MWa (513 MWa after EE) Retail load before EE (excl. 5-year opt-outs) Coal – Boardman Natural Gas – Port Westward, Coyote, Beaver as an intermediate resource Hydro – PGE-owned & Mid-C contracts Wind – Biglow, Klondike II, Vansycle Coal – Colstrip Retail load including EE (excl. 5-year opt-outs) Load-Resource Balance (2012-2021) Energy 33

Energy Action Plan 1) Up to 100 MWa; actual purchases will depend on balancing needs; total might not foot due to rounding PGE Load With EE Savings 2,620 Remove 5-year Opt-Outs -128 Existing PGE & Contract Resources -1,860 PGE Resource Target 632 Resource Actions Thermal: CCCT 406 Combined Heat & Power 2 Renewable: ETO Energy Savings 119 Existing Contract Renewal - 2015 RPS Compliance 101 To Hedge Load Variability(1) : Short and Mid-Term Market Purchases 100 Total Incremental Resources 728 Energy (Deficit)/Surplus 96 Total Resource Actions 632 Annual Energy Action Plan for 2015 Annual MWa 34

Capacity Load-Resource Balance 0 1000 2000 3000 4000 5000 6000 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 A v ai lable Capacit y ( M W ) Load-Resource Balance (2012-2021) Winter Capacity Long-Term Contracts & DSG 2015 Shortfall 1,409 before EE 1,233 after EE Peak Hour Load after EE + Reserves (excl. 5-year opt-outs) Coal - Boardman Natural Gas - Port Westward, Coyote, Beaver as an intermediate resource Hydro - PGE-owned & Mid-C contracts Wind - Biglow 1-3, Klondike II, Vansycle Coal - Colstrip Peak Hour before EE + Reserves (excl. 5- year opt-outs) 35

1) Approx. 6% of generation; excludes reserves for action plan acquisitions 2) 6% of PGE net system load excluding 5-year opt-outs. Total might not foot due to rounding Capacity Action Plan PGE Load with EE Savings Remove 5-year Opt-Outs Operating Reserves(1) Contingency Reserves(2) Existing PGE & Contract Resources PGE Resource Target Resource Actions Thermal: CCCT Combined Heat & Power Renewable: Existing Contract Renewal 2015 RPS Compliance To Hedge Load Variability: Capacity Only Resources: Flexible Peaking Supply Customer-Based Solutions (Capacity Only): DSG (2010-2013) Demand Response Seasonally Targeted Resources: ETO Capacity Savings Bi-Seasonal Capacity Winter-Only Capacity Total Incremental Resources Capacity Action Plan for 2015 4,150 -144 183 1,409 232 -3,012 441 2 - 15 Short and Mid-Term Market Purchases 100 - 200 70 67 176 202 152 1,409 MW 36

Appendices 1. Financials 2. Resource planning 3. Regulatory environment 4. Business initiatives – details 37

Regulatory Environment  Oregon Public Utility Commission – Governor-appointed Commission with staggered four-year terms (John Savage 3/2013, Stephen Bloom 12/2015, Susan Ackerman (chair) 3/2016)  Return on Equity & Capital Structure – 10.0% allowed return on equity – 50% debt and 50% equity capital structure  Forward Test Year  Net Variable Power Cost Recovery – Annual Power Cost Update Tariff – Power Cost Adjustment Mechanism: employs fixed deadbands and earnings test  Decoupling – Per 2011 General Rate Case order, mechanism to continue through the end of 2013  Renewable Energy Standard – Standard requires PGE to serve 25% of its retail load from renewable sources by 2025  Renewable Adjustment Clause (RAC) – PGE can recover costs of renewable resources through a separate tracking mechanism  Integrated Resource Plan – OPUC “Acknowledgement” is standard – 2009 IRP: Long-term analysis outlining 20-year resource strategy – 2011 IRP Update: Filed November 23, 2011 38

Recovery of Power Costs • Annual reset of rates based on forecast of net variable power costs (NVPC) for the coming year • Subject to OPUC prudency review and approval, new prices go into effect on or around January 1 of the following year • PGE absorbs 100% of the costs/benefits within the deadband, and amounts outside the deadband are shared 90% with customers and 10% with PGE • An annual earnings test is applied as part of the PCAM, using the regulated ROE as a threshold • Customer surcharge occurs to the extent it results in PGE’s actual regulated ROE being no greater than 9.0%; customer refund occurs to the extent it results in PGE’s actual regulated ROE being no less than 11.0% Power Cost Adjustment Mechanism (PCAM) Annual Power Cost Update Tariff 1) Per OPUC’s 2011 General Rate Case Order, deadband ranges are fixed and no longer represent 75 – 150 basis points of ROE 10.0% 9.0% 11.0% R e tu rn o n E quit y R e tu rn o n E quit y Baseline NVPC 90/10 Sharing ($15) million(1) $30 million(1) Customer Refund Customer Refund 90/10 Sharing Customer Surcharge Deadband Customer Surcharge Power Cost Sharing Earnings Test 39

Additional Renewable Resources Integrated Resource Plan addresses procurement of wind or other renewable resources to meet requirements of Oregon’s Renewable Energy Standard by 2015. Such need is now approximately 100 MWa (or 300 MW wind nameplate capacity) Year Renewable Target 2011 5% 2015 15% 2020 20% 2025 25% In 2011, Renewable Energy Standard qualifying renewables supplied approximately 10% of PGE’s retail load. In addition, PGE has several solar projects in place or in progress, for a total of approximately 8 MW Renewable Adjustment Clause (RAC) 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. Renewable Energy Standard 40

The decoupling mechanism is intended to allow recovery of margin lost due to a reduction in sales of electricity resulting from customers’ energy efficiency and conservation efforts Includes a Sales Normalization Adjustment mechanism (SNA) for residential and small non- residential customers (≤ 30 kW) 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 2011 general rate case. The SNA mechanism applies to approximately 58% of 2011 base revenues – 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. The LRR mechanism applies to approximately 29% of 2011 base revenues OPUC order in PGE’s 2011 General Rate Case, authorized the continuation of the decoupling mechanism through December 31, 2013 For 2011, PGE recorded an estimated customer refund of approximately $1.5 million as weather adjusted use per customer was slightly more than levels included in the 2011 General Rate Case Decoupling Mechanism 41 (in millions) Q1 Q2 Q3 Q4 2011 Sales Normalization Adjustment $0.4 ($0.6) $1.0 ($1.4) ($0.6) Loss Revenue Adjustment $0.1 ($0.6) ($0.2) ($0.2) ($0.9) Total adjustment $0.5 ($1.2) $0.8 ($1.6) ($1.5) Note: refund/surcharge = (negative)/positive

Appendices 1. Financials 2. Resource planning 3. Regulatory environment 4. Business initiatives – details 42

Boardman 2020 Emissions Controls Emissions Controls at the Boardman Plant  In December 2010, the Oregon Environmental Quality Commission (OEQC) approved revised Best Available Retrofit Technology (BART) rules  June 2011, EPA approved revised rules, which were published in the Federal Register in July 2011  To comply with the revised rules, PGE plans to: – Use lower sulfur coal to fire the plant’s boiler – Install low NOx burners and modified over-fired air ducts – Install dry sorbent injection systems (DSI) to address SO2 and mercury • Contingent upon successful pilot testing: − PGE would meet a 0.4 lb SO2/MMBtu limit using DSI by July 2014 − PGE would meet a 0.3 lb SO2/MMBtu limit using DSI by July 2018 – Cease coal-fired operations no later than December 31, 2020  PGE Share of 2011 capital spending on Boardman controls was approximately $17 million – Installed low NOx burners and over-fire air ducts – Mercury controls installed and performance testing is complete  Remaining PGE capital cost estimated at $22 million in 2011 and 2012  In December 2011, EPA released its final utility MACT rule; based on our preliminary full-scale testing results, Boardman should be able to meet MACT requirements once currently planned controls are in place 43

Cost Efficiency Initiatives 44  Company-wide benchmarking to identify best practices and standards  2020 Vision Technology Upgrades – Financial system and supply chain replacement project – Timekeeping System – Enterprise Asset Management • Transmission & Distribution • Generation • Information Technology  Process Improvements – Centralized Dispatch – Supervisor in the Field – Mobile & Scheduling

Smart Meter Project Smart Meters  Provide two-way communications with residential and commercial customers  Vendor: Sensus  Technology: FlexNet radio frequency technology  Completed installation of 825,000 meters as of December 31, 2010  Capital costs: $145 million  OPUC approved limited term tariff: June 1, 2008 through December 31, 2010 that recovered the remaining investment in old meters. The 2011 General Rate Case includes project costs, net of savings in customer prices effective January 1, 2011 Distribution System  Pursuing direct load control programs  Optimizing distribution system through advanced technology 45

Biglow Canyon Wind Farm  Columbia Gorge, eastern Oregon  450 MW total nameplate capacity  Total cost approximately $1B 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 $321 million $385 million Online date December 2007 August 2009 August 2010 Vendor Vestas Siemens Siemens 46