Update to FY 2008 Integrated Program Review IPR-2 March 18, 2009

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2. 2 Background, Objectives, Schedule and Scope of the Integrated Program Review Update (IPR 2) Overview Power Rates Expense Overview Capital Overview Transmission Rates Expense Overview Capital Overview Agency Services Expense Overview Capital Overview Next Steps Financial Disclosure IPR-2 Materials

3. 3 Integrated Program Review Update Background BPA held a public process, the Integrated Program Review, from May 2008 through August 2008. The purpose of that process was to: Present all BPA’s costs, Power, Transmission and Agency Services, both expense and capital, in one forum, consistent with the structure developed coming out of the Regional Dialogue. Allow customers, other stakeholders and interested parties an opportunity to review, ask questions about, and comment on any changes since the Close-Out Report from November 2008 to BPA’s proposed spending levels for FY 2010-2011 and proposed capital investment levels for FY 2009-2013. A Close-Out Report was released in November 2008, laying out the decisions and explanations for those decisions on spending levels and capital investment levels. In that report, BPA stated: Integrated Program Review Parameters The rate case is a formal hearing process, with a Hearing Officer, which sets rates based on costs. The Integrated Program Review (IPR) is a collaborative informal process designed to lay out the major program costs and seek customer feedback and suggestions for each program area prior to these numbers being included in rates.

4. 4 (Continued from the November 2008 Close-Out Report) The decisions on FY 2010-2011 program spending levels outlined here are based on the best information available. We believe that by next spring we should have additional information that may cause revisions to some program levels for FY 2010-2011. Additional information will likely become available on the following topics: A better understanding of BPA’s role in the development of energy efficiency and renewable resources as a result of the Northwest Energy Efficiency Task Force activities, recommendations from the Northwest Power and Conservation Council’s 6th Power Plan which will establish new conservation targets for the region, and a public process BPA intends to hold to discuss its role in energy efficiency; Better understanding of the internal costs associated with the transition to new power contracts and rates in 2012; More clarity on fish and wildlife costs; Further work on Network Open Season planning; Further work on BPA’s asset planning and resource strategy resulting in improved estimates of realistically achievable capital spending; and Evaluation of the implications for BPA and the region of recent events in global financial markets and indications of a severe economic downturn. The decisions outlined here will be the basis for our initial rate proposals. We intend to hold a subsequent, abbreviated program review next spring to reconsider the program levels in light of the increased information available at that time.

5. 5 Objective

6. 6 Integrated Program Review Scope The IPR is BPA’s public involvement process for: The costs that go into power and transmission rates, with a primary focus on the major program areas that make up the bulk of power and transmission costs. Input received in this process will inform BPA’s decisions on the program levels that will be included in the 2010-2011 Power and Transmission Rate Case Final Proposals. Program levels will not be revisited in the two rate cases. The decision processes for the following topics are in the Power and Transmission rate cases, and they will not be addressed here: Loads and Resources Revenue Credits including Secondary Sales Revenues Billing Determinants Residential Exchange Costs Reserve Levels Ancillary Services Rate Design Rate Level While depreciation, amortization, net interest and non-Federal debt service are described in this process, those are also not decided in this process. They are results of many factors, including capital investment levels, interest rate environment, and debt management decisions. A preliminary estimate of Power and Transmission Services interest, depreciation and non-federal debt service has been provided for information only. The final amounts will be determined in the rate case and could be considerably different based on changes in capital forecast, debt management actions, and changes in projected interest income on cash in the BPA Fund.

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8. 8 Power

9. 9 Drivers of Power Costs The increases in Power Services costs as described in IPR are largely attributable to: Columbia Generating Station nuclear plant costs, due to increases in operations, maintenance and capital expenses needed to ensure safe, reliable and efficient operation of the plant. Notably, this includes replacement of the main condenser in 2011. In addition, the extended outage needed for the condenser replacement will cause significant lost revenues and power replacement costs in 2011. BPA does not directly control these costs, but agrees that increases are necessary. New 2008 Biological Opinion requirements and implementation of new agreements with participating tribes and states (the Columbia Basin Fish Accords) will result in substantial increased spending for on-the-ground projects to boost protection and survival of threatened and endangered Columbia Basin salmon. Increased Operations and Maintenance costs on the hydro system to maintain and improve its reliability and output.

10. 10 Power Expenses

11. 11 Columbia Generating Station

12. 12 Corps & Reclamation

13. 13 Long Term Generation Program

14. 14 Renewable Generation Program

15. 15 Conservation Program

16. 16 Internal Operations & Post-Retirement Contribution

17. 17 Transmission Purchases, Reserve/Ancillary Services

18. 18 Fish & Wildlife Costs

19. 19 Fish & Wildlife Costs (continued)

20. 20 Net Interest, Amortization, Depreciation & Non-Federal Debt Service

21. 21 Other, Colville Settlement and Non-Operations

22. 22 Power Function Capital Expenditures Actuals for FY 2007-2008, Forecasted FY 2010-2014

23. 23 COE/BOR Capital Expenditures

24. 24 Fish & Wildlife Capital Expenditures

25. 25 Conservation Capital Expenditures

26. 26 Columbia Generating Station Capital

27. 27 Columbia River Fish Mitigation Capital

28. 28 Transmission

29. 29 Transmission Expenses Vickie discussed the various factors driving our cost increases. As we look deeper into the individual programs, the drivers become more evident: (these examples are not exhaustive) System Operations – Support for mandatory reliability standards, Compliance reporting and Wind Integration Scheduling – Increased workload due to increasing demands for capacity Marketing – Order 890 scoping and implementation, conditional firm implementation, automation to keep up with changing needs and requirements Business Support – Increased Corporate and Transmission support for compliance activities, COOP and Asset Management implementation, CIP/NERC reporting, legal support of land/ROW issues, contract support and litigation, and increased logistics support for maintenance activities. System Maintenance – Implementation of the facilities asset management plan, seismic mitigation for critical facilities/equipment, implementing bare-handing as a maintenance practice, NERC/WECC compliance for ROW maintenance, LiDAR for danger tree tracking. Environmental Operations – Compliance activities for the Clean water Act and the Toxic Substances Control Act. System Development – Increased support and changing standards for compliance with the mandatory requirements being implemented. Agency Services – Increased Research and Development and support of the transmission programs. These will be discussed in depth later in the presentation. Non-BBL Acquisition and Ancillary Services – This includes the lease payments for the Master Lease program and payments for reliability re-dispatch. Non-Federal Debt Service –Net Interest costs associated with the LGIA projects. Other – Includes an undistributed expense reduction of $2M each year. Interest and Depreciation – These are driven by the capital projects being completed. Vickie discussed the various factors driving our cost increases. As we look deeper into the individual programs, the drivers become more evident: (these examples are not exhaustive) System Operations – Support for mandatory reliability standards, Compliance reporting and Wind Integration Scheduling – Increased workload due to increasing demands for capacity Marketing – Order 890 scoping and implementation, conditional firm implementation, automation to keep up with changing needs and requirements Business Support – Increased Corporate and Transmission support for compliance activities, COOP and Asset Management implementation, CIP/NERC reporting, legal support of land/ROW issues, contract support and litigation, and increased logistics support for maintenance activities. System Maintenance – Implementation of the facilities asset management plan, seismic mitigation for critical facilities/equipment, implementing bare-handing as a maintenance practice, NERC/WECC compliance for ROW maintenance, LiDAR for danger tree tracking. Environmental Operations – Compliance activities for the Clean water Act and the Toxic Substances Control Act. System Development – Increased support and changing standards for compliance with the mandatory requirements being implemented. Agency Services – Increased Research and Development and support of the transmission programs. These will be discussed in depth later in the presentation. Non-BBL Acquisition and Ancillary Services – This includes the lease payments for the Master Lease program and payments for reliability re-dispatch. Non-Federal Debt Service –Net Interest costs associated with the LGIA projects. Other – Includes an undistributed expense reduction of $2M each year. Interest and Depreciation – These are driven by the capital projects being completed.

30. 30 System Operations

31. 31 Scheduling

32. 32 Marketing

33. 33 Business Support

34. 34 System Maintenance with Environmental Operations

35. 35 Transmission Engineering

36. 36 Agency Services & Post Retirement Contribution

37. 37 Acquisition & Ancillary Services

38. 38 Non-Federal Debt Service, Depreciation, Amortization & Net Interest Expense Program Background: On average the typical program components are: 43 percentage Net Interest – Comprised of interest on bonds and appropriations netted against interest credit from the Bonneville Fund. 56 percentage Depreciation – The depreciation of revenue-producing assets and on-going infrastructure investments through BPA and third-party funding of transmission assets. 1 percentage Non-Federal Debt Service – The interest and AFUDC for projects associated with the Large Generator Integration Agreements, primarily wind projects. Strategic Objectives: S4 – Transmission Access & Rates: Open, non-discriminatory transmission services are provided at rates that are kept low through achievement of BPA’s objectives at the lowest practical cost. IPR 2 Drivers: IPR 1 estimates were provided in the IPR Close-Out Report for FY 2010-2011. IPR 2 numbers are preliminary estimates provided for information only. The final amounts will be determined in the rate case and could be considerably different based on changes in capital forecast, debt management actions, and changes in projected interest income on cash in the BPA Fund. IPR 1 Drivers Increased capital investment Change in projected interest income due to change in cash balances Debt management actions

39. 39 Transmission Capital

40. 40 $800M is the total direct cost of projects listed on this page for reinforcements and reliability to loads. Projects provide: 1) Voltage support & reliable transmission system for open access 2) Provides for relief of transmission congestion 3) Maintain reliable service to loads, 4) Assure compliance with WECC and NERC reliability standards. The emphasis for the IPR FY09 - FY13 plan and the major projects listed on this page is to provide congestion relief and compliance with reliability standards I-5 Corridor: Construct a new 500 kV line between southwest Washington (in the vicinity of Castle Rock, WA ) and northwest Oregon to reinforce this portion of the I-5 Corridor transmission system. Purpose of the project is to address the following: Transmission Service Requests for long-term firm transmission Congested path issues Increasing summer peak loads and contractual obligations to serve them Reduce dependence on existing RAS while maintaining transmission system reliability Project Schedule: The project schedule depends on the outcome of the Network Open Season process and the result of an environmental impact study. BPA estimates that it could take up to three years to prepare the environmental impact statement (EIS). If the project is approved, construction could take an additional three years from that decision. McNary-John Day 500-kV Line/Big Eddy-Station Z 500-kV Line (includes new 500 kV substation): Relieves transmission congestion - Presently, a large amount of wind generation is being proposed west of McNary Substation closer to Slatt and John Day Substations. - In response to this, there is a need to increase transmission capability across the WOM/WOS/WOJ paths. - Transmission reinforcement is needed to provide firm transmission service for proposed generation projects and increase system reliability to the Portland load area. Olympic Peninsula Reinforcement Project: Compliance with BPA/WECC/NERC Planning Standards and increases system reliability to the Olympic Peninsula - Meets BPA’s Reliability Criteria for System Planning: This project mitigates the effects of a single element loss of either the Olympia 500/230kV transformer or Paul-Olympia 500kV line for 1 in 20 load level (heavy winter). -NERC/WECC Reliability Standards for System Performance: The project also mitigates the effects of multiple common mode contingencies for 1 in 2 load level (normal winter peak and summer peak) such as the loss of two or more Bulk Electric System (BES) Elements up to the Shelton substation. - NWPP Voluntary Northwest Transmission Adequacy Guidelines: This project also addresses load service planning guidelines specifically LS-G3 N-2 (common tower and breaker failure) Item C (above 300MW of total local area load) to meet all system reliability requirements but may involve some interruption to load service. Libby (FEC)-Troy Rebuild Project: Addresses safety hazards and provides load-service reliability The line deteriorating to the point where it needs a major rebuild to continue serving customer loads safely and reliably. Wood poles cannot safely withstand structural loads. Most cross arms are rotting and show splitting and damage. Conductor fittings have begun to fail due to corrosion. One previous conduct fitting failure resulted in a serious fire. Cross Cascades :The cross cascades north & south paths are thermal and/or voltage stability limited. Installation of series capacitors on Schultz-Raver 500-kV lines #3 & #4 is needed by 2013 to serve the Puget Sound area load reliably and relieve the limitation for the Cross cascades North to support the load growth in the area. A 500-kV Shunt capacitor addition at Allston is planned by 2010 to serve the Willamette Valley load area reliably. Seattle Transformer:- A 500/230-kV transformer is needed in the South Puget Sound area (at Maple Valley or Covington) to serve load reliability by 2013 time frame. $800M is the total direct cost of projects listed on this page for reinforcements and reliability to loads. Projects provide: 1) Voltage support & reliable transmission system for open access 2) Provides for relief of transmission congestion 3) Maintain reliable service to loads, 4) Assure compliance with WECC and NERC reliability standards. The emphasis for the IPR FY09 - FY13 plan and the major projects listed on this page is to provide congestion relief and compliance with reliability standards I-5 Corridor: Construct a new 500 kV line between southwest Washington (in the vicinity of Castle Rock, WA ) and northwest Oregon to reinforce this portion of the I-5 Corridor transmission system. Purpose of the project is to address the following: Transmission Service Requests for long-term firm transmission Congested path issues Increasing summer peak loads and contractual obligations to serve them Reduce dependence on existing RAS while maintaining transmission system reliability Project Schedule: The project schedule depends on the outcome of the Network Open Season process and the result of an environmental impact study. BPA estimates that it could take up to three years to prepare the environmental impact statement (EIS). If the project is approved, construction could take an additional three years from that decision. McNary-John Day 500-kV Line/Big Eddy-Station Z 500-kV Line (includes new 500 kV substation): Relieves transmission congestion - Presently, a large amount of wind generation is being proposed west of McNary Substation closer to Slatt and John Day Substations. - In response to this, there is a need to increase transmission capability across the WOM/WOS/WOJ paths. - Transmission reinforcement is needed to provide firm transmission service for proposed generation projects and increase system reliability to the Portland load area. Olympic Peninsula Reinforcement Project: Compliance with BPA/WECC/NERC Planning Standards and increases system reliability to the Olympic Peninsula - Meets BPA’s Reliability Criteria for System Planning: This project mitigates the effects of a single element loss of either the Olympia 500/230kV transformer or Paul-Olympia 500kV line for 1 in 20 load level (heavy winter). -NERC/WECC Reliability Standards for System Performance: The project also mitigates the effects of multiple common mode contingencies for 1 in 2 load level (normal winter peak and summer peak) such as the loss of two or more Bulk Electric System (BES) Elements up to the Shelton substation. - NWPP Voluntary Northwest Transmission Adequacy Guidelines: This project also addresses load service planning guidelines specifically LS-G3 N-2 (common tower and breaker failure) Item C (above 300MW of total local area load) to meet all system reliability requirements but may involve some interruption to load service. Libby (FEC)-Troy Rebuild Project: Addresses safety hazards and provides load-service reliability The line deteriorating to the point where it needs a major rebuild to continue serving customer loads safely and reliably. Wood poles cannot safely withstand structural loads. Most cross arms are rotting and show splitting and damage. Conductor fittings have begun to fail due to corrosion. One previous conduct fitting failure resulted in a serious fire. Cross Cascades :The cross cascades north & south paths are thermal and/or voltage stability limited. Installation of series capacitors on Schultz-Raver 500-kV lines #3 & #4 is needed by 2013 to serve the Puget Sound area load reliably and relieve the limitation for the Cross cascades North to support the load growth in the area. A 500-kV Shunt capacitor addition at Allston is planned by 2010 to serve the Willamette Valley load area reliably. Seattle Transformer:- A 500/230-kV transformer is needed in the South Puget Sound area (at Maple Valley or Covington) to serve load reliability by 2013 time frame.

41. 41 Area & Customer Service Area & Customer Service: Dates shown on this page are energization dates. Total direct project cost (all years $) for these projects are: City of Centralia $5.2M S. Oregon Coast - Rogue SVC $10M Lower Valley - $26.5MArea & Customer Service: Dates shown on this page are energization dates. Total direct project cost (all years $) for these projects are: City of Centralia $5.2M S. Oregon Coast - Rogue SVC $10M Lower Valley - $26.5M

42. 42 Upgrades and Additions Program Background: Upgrades and Additions assure that BPA meet’s reliability standards and contractual obligations to its customers for serving load. Strategic Objectives: S4 – Transmission Access & Rates: Open, non-discriminatory transmission services are provided at rates that are kept low through achievement of BPA’s objectives at the lowest practical cost. IPR 2 Drivers: No Change IPR 1 Drivers: Driven by reliable service to loads and Asset Plan. Replacement of older communications and controls with newer technology. Albany – Eugene rebuild – $10 million in 2010. Celilo Upgrades – transformers, etc – $24 million in 2010 and 2011. Control Center (CC) Systems – modernization, congestion mgmt, RAS automation, training facility, cyber security, etc. Fiber– SONET rings, getting off analog microwave: $10-20 million per year. Critical spare transformers at 5 locations. Maintaining access roads: $10-15 million per year. Total direct project cost (all years $) for these projects are: Albany - Eugene Rebuild - $10M Celilo - Upgrades - $63M ($24M is just for FY2010-11) CC Systems - $7M-$8M per year Critical spare transformers - $19.5M - the 5 locations are: Ponderosa Monroe Sickler Hot Springs Alvey Also included in IPR budget FY09 - FY11but not listed specifically on this page is Tucannon -Walla Walla Line Rebuild $24.7M Total direct project cost (all years $) for these projects are: Albany - Eugene Rebuild - $10M Celilo - Upgrades - $63M ($24M is just for FY2010-11) CC Systems - $7M-$8M per year Critical spare transformers - $19.5M - the 5 locations are: Ponderosa Monroe Sickler Hot Springs Alvey Also included in IPR budget FY09 - FY11but not listed specifically on this page is Tucannon -Walla Walla Line Rebuild $24.7M

43. 43 System Replacements Total direct project cost (all years $) for these projects that aren't already listed on this page: Substation Equipment spares $14M-$15M Transformer Spares $70M - to happen FY11-14 Celilo Replacements $38M Total direct project cost (all years $) for these projects that aren't already listed on this page: Substation Equipment spares $14M-$15M Transformer Spares $70M - to happen FY11-14 Celilo Replacements $38M

44. 44 Environment PCB projects are approximately $2M a year. All of the caps are completed, now replacing other PCB containing equipment, like transformers, etc. Storm water projects are @$3M a year. Addresses regulatory and liability issues at BPA facilities likely to adversely affect water and environmental issues. BPA's Environment Capital Program addresses two program areas; (1) Reducing Polychlorinated BiPhenyls (PCBs,) a persistent bioaccumulative toxic (PBT) chemical and (2) Water resources protection for BPA’s transmission system. PCB Initiative – Replace equipment containing high levels of PCBs on the transmission system to reduce environmental risks and to resolve and/or prevent regulatory non-compliance with the Toxic Substances Control Act and state regulations. Water Initiative - Upgrade/install drainage treatment and containment systems at environmentally sensitive facilities to maintain water resources protection and to resolve and/or prevent regulatory non-compliance to ensure Transmission facilities (substations, maintenance complexes) storm water discharges shall meet all Federal and State standards established under the Clean Water Act.PCB projects are approximately $2M a year. All of the caps are completed, now replacing other PCB containing equipment, like transformers, etc. Storm water projects are @$3M a year. Addresses regulatory and liability issues at BPA facilities likely to adversely affect water and environmental issues. BPA's Environment Capital Program addresses two program areas; (1) Reducing Polychlorinated BiPhenyls (PCBs,) a persistent bioaccumulative toxic (PBT) chemical and (2) Water resources protection for BPA’s transmission system. PCB Initiative – Replace equipment containing high levels of PCBs on the transmission system to reduce environmental risks and to resolve and/or prevent regulatory non-compliance with the Toxic Substances Control Act and state regulations. Water Initiative - Upgrade/install drainage treatment and containment systems at environmentally sensitive facilities to maintain water resources protection and to resolve and/or prevent regulatory non-compliance to ensure Transmission facilities (substations, maintenance complexes) storm water discharges shall meet all Federal and State standards established under the Clean Water Act.

45. 45 Customer-Financed/Credits/Radio Spectrum/PFIA These are not part of our revenue requirement. They are mentioned here because they use resources Wind Integration – three new 500/230-kV stations $63M - $69M per year California-Oregon Intertie additions $52M total FY09-FY12 Radio Spectrum Relocation projects- $48M - 6 year program These are not part of our revenue requirement. They are mentioned here because they use resources Wind Integration – three new 500/230-kV stations $63M - $69M per year California-Oregon Intertie additions $52M total FY09-FY12 Radio Spectrum Relocation projects- $48M - 6 year program

46. 46 Agency Services

47. 47 Agency Services Expenses

48. 48 Executive Offices

49. 49 Chief Risk Officer

50. 50 Technology Innovation & Confirmation

51. 51 Public Affairs

52. 52 Internal Audit

53. 53 Finance

54. 54 Corporate Strategy

55. 55 Supply Chain Policy and Governance

56. 56 Regulatory Affairs

57. 57 Security & Emergency Management

58. 58 General Counsel

59. 59 Customer Support Services Key points to mention: Prior to FY07, CSS functions were Power and Transmission activities, CSS functions were consolidated in the Marketing and Sales EPIP in order to improve customer service, reduce redundant functions, enhance internal process efficiency, implement internal risk controls, and comply with FERC Standards of Conduct compliance. Challenges unforeseen by the M&S EPIP include increased workload effecting all KS functions (e.g. the new RD contracts complexity, WECC/NERC compliance, WREGIS participation, new Network Open Season contracts and additional O&M transmission reliability related agreements). Key points to mention: Prior to FY07, CSS functions were Power and Transmission activities, CSS functions were consolidated in the Marketing and Sales EPIP in order to improve customer service, reduce redundant functions, enhance internal process efficiency, implement internal risk controls, and comply with FERC Standards of Conduct compliance. Challenges unforeseen by the M&S EPIP include increased workload effecting all KS functions (e.g. the new RD contracts complexity, WECC/NERC compliance, WREGIS participation, new Network Open Season contracts and additional O&M transmission reliability related agreements).

60. 60 Safety

61. 61 Human Capital Management

62. 62 Supply Chain Management

63. 63 Workplace Services

64. 64 IT Expense

65. 65 Agency Service Capital

66. 66

67. 67 Security & Emergency Management Capital

68. 68 General Counsel Capital

69. 69 Workplace Services Capital

70. 70 IT Capital

71. 71 Ways to Participate All forums are open to the public and will be noticed on the IBR external web site at: http://www.bpa.gov/corporate/Finance/IBR/IPR/ All Technical and Managerial workshops will be held at BPA Headquarters. The comment period for the IPR2 opens Wednesday, March 18, 2009. Close of comment is April 18, 2008. You have several options to provide comments to BPA: Attend one or more of the scheduled workshops and give BPA your comments. Discuss your input with your Customer Account Executive, Constituent Account Executive, or Tribal Liaison. Submit written comments to Bonneville Power Administration, P.O. Box 14428, Portland, OR 97293-4428. Submit comments via e-mail to: comment@bpa.gov or submit on line at: http://www.bpa.gov/comment. Comments can also be sent via fax to (503) 230-3285.

72. 72 BPA’s Financial Disclosure Information All FY 2009-2013 information was provided in March 2009 and cannot be found in BPA-approved Agency Financial Information but is provided for discussion or exploratory purposes only as projections of program activity levels, etc. All FY 2007-2008 actuals are provided in March 2009 and are consistent with audited actuals that contain BPA-approved Agency Financial Information. FY 2009 Rate Case data has been developed for publication in rates proceeding documents and is being provided by BPA on March 18, 2009.