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Power Function Review II Technical Workshop

Power Function Review II Technical Workshop. February 8, 2006. Table of Contents. Scorecard – Pg.3-4 Conservation – Pg. 5-10 Renewables – Pg. 11-17 Capital Cost Recovery – Pg. 18-33 Revenue Requirement Analysis – Pg. 20-21 Amortization of Conservation Acquisition Investments – Pg. 22-26

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Power Function Review II Technical Workshop

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  1. Power Function Review IITechnical Workshop February 8, 2006

  2. Table of Contents • Scorecard – Pg.3-4 • Conservation – Pg. 5-10 • Renewables – Pg. 11-17 • Capital Cost Recovery – Pg. 18-33 • Revenue Requirement Analysis – Pg. 20-21 • Amortization of Conservation Acquisition Investments – Pg. 22-26 • Amortization of Fish & Wildlife Investments – Pg. 27-33 • Internal Operations Charged to Power (EPIP) – Pg.34-39 and attachment • Spokane Settlement Update – Pg. 40-43

  3. PFR II: Current Areas Of Priority Focus • Capital Recovery • (-/+) Longer amortization period for conservation • (-) Longer amortization period for fish and wildlife • (-) Use BPA borrowing authority for land and water acquisitions for fish • (-$16M) CGS existing debt extension to 2024 • (-$1.5M) Longer maturity (to 2024) on debt for new CGS investments • (-$24M) Update to reflect 2005 actuals in repayment studies • (+ $5M) Columbia River Fish Mitigation plant-in-service schedule -- DOD IG decision • CGS O&M • (+) Potential increases for deferred maintenance (Probably mostly capital) • (-) Consider increasing capacity factor • Hydro O&M • (-/+) Benchmarking federal projects O&M against other regional hydro projects • (-) Review process used to approve CRFM investments • Residential Exchange • None • Transmission expenses • (-) Review transmission expense for secondary sales

  4. PFR II: Current Areas Of Priority Focus • Fish and Wildlife • (-/+) Re-examine timing for Snake River spill tests • (-/+) F&WL Monitoring and Evaluation (M&E) • "Other" • (-$59M) DSI $59 million annual support ($40M is expected value) • (+) Review Spokane settlement status • Internal Operations • (-) Examine additional EPIP savings • Conservation • (-) Consider conservation done by utilities "on their own nickel" • (-/+) Increase BPA funding for conservation • Renewables • (-$7) Remove Calpine geothermal costs from 2009 • (+) Consider increasing facilitation costs • Long Term Generating Projects • None

  5. Power Function Review IIConservation Program

  6. Average Annual Power Expenses for FY07-09 All Power Purchases $144M (6%) $2.6B Capital Cost Recovery $979M (37%) Columbia Generating Station O&M for Nuclear Plant $234M (9%) Corps and Reclamation O&M for Hydro Plants $241M (9%) Payments to Residential & Small Farm Consumers of IOUs $324M (12%) Transmission Purchases, Reserve/Ancillary Services $184M (7%) Fish and Wildlife Services $143M (6%) Other $125M (5%) Internal Operations Charged to Power Rates $109M (4%) Conservation Program (Expense) $71M (3%) Renewables Program $42M (1%) Long Term Generation Projects $25M (1%)

  7. Conservation Program Discussion Topic 1: Credit conservation done by public utilities “on their own nickel” against BPA’s target, reducing BPA’s spending. BPA’s goal: To achieve BPA’s share of the Council’s Fifth Power Plan conservation targets at the least possible cost to BPA. Crediting cost-effective conservation done by utilities on their own nickel may be consistent with this policy. What it would take: • A tracking mechanism: Done. We have added a feature to the RTF Planning, Tracking and Reporting System for customers to report “self-funded conservation. • A determination of how much self-funded conservation occurs using tracking system data reported at the end of 2006. • A method to give BPA and the region reasonable confidence that the reported savings are real and based on cost-effective measures as defined by the Council. • Evaluate the information and make a decision about whether or not BPA should adjust its conservation targets and budgets for FY 2007 and beyond. This could be accomplished through impact evaluations of utility programs either funded by the utility or by BPA. Criteria for eligibility: Self-funded conservation credited to BPA would need to be incremental to the utility’s own share of the Council’s target.

  8. Conservation Program Issue: • Historically, we have good confidence in the conservation savings accomplished with BPA funds because we design in sufficient rigor up front and we do measurement, oversight and evaluations to confirm the savings are there. Assuming there turns out to be a significant amount of utility ”self-funded” conservation, how should BPA proceed to evaluate these accomplishments so that we have the same level of confidence in the utility installed ECMs as we do in the “BPA-funded” conservation? Feedback needed from participants: • How do we “encourage” utilities to report their “self-funded” conservation (provide information on cost and savings for installed ECMs) in the enhanced RTF Planning, Tracking and Reporting System? • How do we assure a consistent level of M & E for all the reported BPA and utility conservation savings?

  9. Conservation Program Discussion Topic 2: What are the impacts of increasing BPA’s funding for conservation? Status: • For every 5 aMW of incremental conservation savings BPA is able to achieve, there would be a increase in rates of 0.08 mills/kWh ($1.3 M decrease in PF revenues, $2.5 M increase in surplus sales and a cost of $1.5M/aMW for delivering the conservation savings) in the 2007-09 rate period (assumes a market rate of $58/MWh and a PF rate of 30 mills/kWh). • Currently, several generating customers are not meeting their share of the region’s cost-effective conservation targets; many others are concerned about being able to spend all their credits under the new CRC. Feedback needed from participants: • The Council sets the cost-effective conservation targets for the region and BPA is committed to achieving its share of that target. If BPA is proceeding at the pace the Council indicates is appropriate, why should we increase our production? • Do we have a good balance on funding and delivery now? Would additional funding, in the short term, really increase production or are there other things that need to be done to ramp up delivered conservation savings in the future?

  10. Conservation Program Initial Proposal PBL Total Conservation Forecast FY 2007 - 2009 Initial Proposal Conservation Program Annual Targets and Budgets *Assumes $6M/yr of the $42M/yr from a separate renewables budget will be spent on renewables. + Includes a 15% administrative cost allowance

  11. Power Function Review IIRenewables Program

  12. Average Annual Power Expenses for FY07-09 All Power Purchases $144M (6%) $2.6B Capital Cost Recovery $979M (37%) Columbia Generating Station O&M for Nuclear Plant $234M (9%) Corps and Reclamation O&M for Hydro Plants $241M (9%) Payments to Residential & Small Farm Consumers of IOUs $324M (12%) Transmission Purchases, Reserve/Ancillary Services $184M (7%) Fish and Wildlife Services $143M (6%) Other $125M (5%) Internal Operations Charged to Power Rates $109M (4%) Conservation Program (Expense) $71M (3%) Renewables Program $42M (1%) Long Term Generation Projects $25M (1%)

  13. Renewables 2007-2009, BPA’s Proposal BPA’s Renewable Target will be based on the Council’s 5th Power Plan: • Council’s 5th Power Plan calls for 5000 MW of new wind, region-wide over the next 20 years. BPA’s share of regional load can be assumed to equal to 40%. Arguably, BPA’s share of the Council’s regional renewable futures could be 40%, or up to 100 MW/year. • However, the Council’s Plan predicts fewer resources in the near-term and more later. There fore BPA is proposing to facilitate up to 50 MW of new renewables per year over FY’s 2007-2009 • BPA is proposing to accomplish this MW target at the least cost, spending up to our annual budget (All expenses on Slide 4, excluding resource costs). • BPA will revise our MW target as the Council revises their cost assumptions (which will effect energy assumptions).

  14. Renewables 2007-2009, BPA’s Proposal BPA’s Proposal for Renewable Facilitation 2007-2009: • If BPA moves towards Tiered rates and offers a Renewable Tier II product. It is conceivable that Tier II need could be established and demonstrated as early as FY 2009 via contract mechanisms. • BPA may choose to meet resource needs during FY 2007- 2009 with cost-effective renewables. However, BPA is not proposing to acquire resources in absence of need simply to meet the MW targets. • $6 million/year for the Renewable Option to the Conservation Rate credit. • Dedicate the Green Energy Premiums to RD&D and non-energy producing renewable facilitation activities. • Dedicate the remainder of the 2007 (up to $5.5 million), 2008 (up to $11 million) and 2009 (up to $11 million) facilitation budgets for one-time payments in the form of Grants issued to requirements utilities who purchase new non-federal renewable resources and take the energy to load during the 2007-2009 rate period. Grants would be based on the Renewable Rate credit ($/MWh) for new facilities.

  15. Renewables 2007-2009, FY09 Changes • BPA is proposing to move the Fourmile Hill Geothermal Project out of the 2009 budget and into FY 2010. • In lieu of the Fourmile Hill, BPA is proposing to include $11 million in the FY 2009 budget to facilitate the region meeting the Council’s forecasted wind generation. • In addition, BPA is proposing to make good on it’s commitment (February 2001 ROD on the C&RD Implementation Manual) to back-stop customer renewable spending under the current C&RD program. • As a result of this commitment, BPA is proposing to include an additional $5 million in the FY 2009 facilitation budget, bringing the FY 2009 renewable facilitation budget to $16 million. • Feedback needed from participants: • Is there support for a $11 million FY 2009 facilitation budget in lieu of Fourmile Hill? • Is there support for dedicating the majority of renewable facilitation funds towards grants issued to requirements customers for new renewable investments? If not, what other alternatives should BPA consider?

  16. Renewables 2007-2009 Initial Rate Proposal

  17. Renewables - Cost of BPA Wind

  18. Power Function Review IICapital Cost Recovery

  19. Average Annual Power Expenses for FY07-09 All Power Purchases $144M (6%) $2.6B Capital Cost Recovery $979M (37%) Columbia Generating Station O&M for Nuclear Plant $234M (9%) Corps and Reclamation O&M for Hydro Plants $241M (9%) Payments to Residential & Small Farm Consumers of IOUs $324M (12%) Transmission Purchases, Reserve/Ancillary Services $184M (7%) Fish and Wildlife Services $143M (6%) Other $125M (5%) Internal Operations Charged to Power Rates $109M (4%) Conservation Program (Expense) $71M (3%) Renewables Program $42M (1%) Long Term Generation Projects $25M (1%)

  20. Revenue Requirement Analysis • BPA has updated repayment studies to reflect several changes. While these studies are not the Rate Case Final Proposal studies, they are likely closer than the Rate Case Initial Proposal to what will be in the Final Proposal. This analysis will change if or when other assumptions or variables change. • The following tables illustrated the sum of the capital-related components of the revenue requirement – non-Federal debt service, net Federal interest, depreciation, and minimum required net revenues. • The Rate Case Initial Proposal repayment study was used as the basis for the analysis. FY 2004 was the last complete set of actual debt management actions available for that study. Capital-Related Components of Rate Case Initial Proposal:

  21. Analysis continued • Updated Base: To provide up-to-date analysis for planning purposes, a new base repayment study was run. This entailed: updating 2005 borrowing, repayment, and plant-in-service with actual FY 2005 actions; making technical corrections to EN debt service; assuming that capital additions for CGS would be financed through 2024 instead of 2018; no change to Initial Proposal projected Federal borrowing capital investment forecasts. • This study also introduces two new assumptions. First, BPA will repay about $65 million of variable rate EN debt in FY 2013-2015 instead of when it is due in FY 2016-2017, smoothing out “critical year” peaks. Second, $350 million of EN debt will be refinanced and extended out through 2024. Capital-Related Components of Initial Proposal: • The major components of change when compared to the Initial Proposal include: • Non-Federal debt service decreases by an average of $44 million per year. • Net Federal interest decreases by an average of $7 million per year. • Minimum required net revenues increases by $12 million per year because of higher Federal amortization payments. • Note that the Rate Case Final Proposal will likely include other changes such as updated capital forecasts, CRFM plant-in-service schedules, and EN debt service.

  22. Power Function Review IICapital Cost RecoveryAmortization Period of Conservation Acquisition Investments

  23. Amortization Period of Conservation Acquisition Investments The purpose of this presentation is to provide background on the policy and on the effect of alternative amortization periods.This presentation is for informational purposes only. Decisions on the assumption in the WP-07 power rate case for amortization of conservation acquisition investments will be decided in the rate case.

  24. Evolution of the Policy • The conservation augmentation declining ten-year amortization period will not be applied to investments made after 2006. • The declining ten-year period was used in recognition of the period for which the benefit was to be derived – power augmentation during the rate period. • The conservation program is shifting from augmentation to acquisition, eliminating the reliance on the 2011 contract period for cost recovery. • New conservation acquisition investments are to be amortized using a five year, straight-line method. • Reasons for selecting five years include: • The new policy will limit the growth of SFAS 71 assets over time, reducing the long term effects. This will decrease the risk of stranded investments. It is also viewed more favorably by rating agencies. • When compared to longer amortization periods, a five year period results in the least pressure on borrowing authority. With a five-year period, the use of borrowing authority will peak at $160 million after which principal will be repaid in amounts equal to additional investments. A fifteen-year period will produce a peak of $480 million before principal repayment matches new investments. • Utility industry practice is mixed. Most appear to expense conservation investments in the year incurred. Some use a five or ten-year period. Very few use a period longer than ten years. A five-year period appears to be more consistent with industry practice.

  25. Evolution of the Policy (continued) • The potential amortization period is not unlimited • Accounting standards provide criteria for establishing amortization periods that begin with determining the useful life. • The composite life of conservation measures planned to be installed after FY 2006 as identified by the Council is fifteen years. • Since BPA’s program is designed to implement its portion of the Council plan, fifteen years is essentially the maximum acceptable period.

  26. Effect of a Longer Period • To estimate the effect of changing the amortization period for conservation investments, we changed the conservation assumption in the Updated Base repayment study from 5 years to 15 years. All other assumptions were held static. • Changing the conservation assumption to 15 years produced almost no change in the revenue requirement. The net effect was a reduction of less than $250,000 per year. The effect in later years is more pronounced through 2015 and declines sharply afterward. Estimated Revenue Requirement Impact • The major components of change in FY 2007-2009 when compared to the Updated Base include: • Depreciation decreases by an average of $6.4 million per year. • Net Federal interest increases by an average of $.4 million per year. • Minimum required net revenues increases by $5.7 million per year because of lower depreciation ($6.4 million/yr) and lower Federal amortization ($.7 million/yr).

  27. Power Function Review IICapital Cost RecoveryAmortization Period of BPA’s Fish & Wildlife Program Investments

  28. Amortization of Fish & Wildlife Investments • This presentation is for informational purposes only, to respond to requests to explain and give background on BPA’s accounting policy that determines the amortization period for capital projects in BPA’s Fish and Wildlife Program.

  29. BPA Fish & Wildlife Investments BPA Fish and Wildlife Program capital investment is funded with bonds issued to the U.S. Treasury. BPA has issued debt to the US Treasury since the late 1970’s to finance BPA investments in transmission, fish & wildlife, and conservation, and in direct-funded Corps & Bureau investments. Bonds outstanding are limited by law to $4.45 billion. Interest rates are set at prevailing government corporation rates. Specifically, for BPA’s Fish and Wildlife Direct Program, BPA funds the investments, and issues bonds to Treasury to cover the investment. The term of these bonds is not to exceed the average life of the associated investments, which is 15 years. Interest is paid semi-annually on these bonds, and the principal is paid at the end of the term. Callable bonds may be issued, and can be “called” or paid early, but BPA must then pay a premium. BPA pays the full amount of these investments, then receives credits against its Treasury payment, under section 4(h)(10)(C) of the Northwest Power Act, for the non-power portion of the investment.

  30. BPA Fish & Wildlife Investments This table shows the rate case forecasts for the Fish and Wildlife Program capital investments from FY 2001 through FY 2009, and actual data through 2005. • Fish and Wildlife Projects that BPA has been capitalizing include: • Fish hatcheries • Fish screens • Land acquired for wildlife habitat • Though these assets don’t generate revenue, they do provide benefit to BPA by helping to achieve mitigation requirements under the Act. These measures have been capitalized under BPA policy based on FAS 71, resulting in these assets being included in our rate structure.

  31. GAAP Relating to Capitalization • Statement of Financial Accounting Standards No. 71 (FAS 71), Accounting for the Effects of Certain Types of Regulation, is the standard that allows BPA to capitalize costs relating to Fish and Wildlife mitigation. • Without FAS 71, BPA would not be able to capitalize its Fish and Wildlife mitigation costs, which are non-revenue producing assets. • BPA must follow Generally Accepted Accounting Principles (GAAP) • GAAP – principles promulgated by all the relevant standard-setting bodies – currently, the FASB, including its Emerging Issues Task Force’s consensus summaries and discussion issues, and the AICPA’s Accounting Standards Executive Committee (AcSEC).

  32. Fish and Wildlife Capitalization Policy • The Pacific Northwest Electric Power Planning and Conservation Act of 1980 (Northwest Power Act) was used in establishing BPA’s Fish and Wildlife capitalization policy: • The “Regional Act” states in Sec. 4(h)(10)(b) that budgets for the construction of capital facilities with an estimated life of greater than 15 years and an estimated cost of at least $1,000,000 shall be funded in the same manner and in accordance with the same procedures as major transmission facilities under the Federal Columbia River Transmission System Act. • The policy that BPA established in 1984 requires that: • estimated costs exceed $1,000,000 • the project have a useful life over 15 years • FAS 71 Asset requirements are observed including, • rates are set to recover the costs over time • the project must provide a measurable future benefit which is defined as fulfilling a legal obligation of the FCRPS or providing an irrevocable credit against FCRPS legal obligations

  33. Corps and Bureau Assets What is the capitalization policy for Corps or Bureau fish and wildlife projects? • The Corp and Bureau receive appropriations for fish mitigation projects at the dams. • Both organizations follow their agency-wide policy relating to categorizing costs as expense or capital. • The Corps and Bureau do not capitalize costs under the provisions of FAS 71, and have no ability to use FAS 71. • When the Corps or Bureau determines that costs are capital, the asset(s) are placed in service upon completion at the facility where they were constructed or, for system-wide assets, at those facilities receiving a benefit. • BPA depreciates Corps assets over a 75 year system-life; Bureau system life is 76 years.

  34. Power Function Review IIInternal Operations Charged to Power (EPIP)

  35. Average Annual Power Expenses for FY07-09 All Power Purchases $144M (6%) $2.6B Capital Cost Recovery $979M (37%) Columbia Generating Station O&M for Nuclear Plant $234M (9%) Corps and Reclamation O&M for Hydro Plants $241M (9%) Payments to Residential & Small Farm Consumers of IOUs $324M (12%) Transmission Purchases, Reserve/Ancillary Services $184M (7%) Fish and Wildlife Services $143M (6%) Other $125M (5%) Internal Operations Charged to Power Rates $109M (4%) Conservation Program (Expense) $71M (3%) Renewables Program $42M (1%) Long Term Generation Projects $25M (1%)

  36. Internal Operations Charged To Power • Program: • This program is driven by BPA’s strategic direction: “Effective cost management (with emphasis on best practices, innovation and simplicity) through our systems and processes.” • Program components of $116M/year annual expense for FY07-09: • 77% Employee Compensation– Personnel compensation and overtime for BPA staff and compensation for contract labor • 14% Service Contracts – Such as projects to optimize the use of water at hydro projects thereby increasing generating output and secondary sales • 9% Other – Travel, training, materials & supplies, rents & utilities, and miscellaneous • Risks: • Unanticipated requirements from new industry requirements, customers, constituents, and other stakeholders • Opportunities for Reductions: • Enterprise Process Improvement effort • Implementation of Voluntary Separation Incentive & Voluntary Early Retirement Authority • Position Management Initiative to reduce overall grade structure • Drivers of Change: • Total PBL staff has declined. Decreased staffing in many areas has been offset by increases in operational functions, partly reflecting efforts to extract more generation from the hydro system through various efficiency projects, and Slice staffing.

  37. BPA FTE: 1972 to 2004 Internal Operations Charged To Power

  38. Internal Operations Charged To Power BPA FTE: 1994 to 2009 BPA will manage to lower FTE amounts 05-09. EPIP and One BPA initiative may lead to even lower FTE. The increase in corporate FTE and decrease in PBL and TBL FTE from 04 to 05 is due to IT consolidation

  39. Internal Operations Charged To Power See EPIP Attachment

  40. Power Function Review IISpokane Settlement

  41. Average Annual Power Expenses for FY07-09 All Power Purchases $144M (6%) $2.6B Capital Cost Recovery $979M (37%) Columbia Generating Station O&M for Nuclear Plant $234M (9%) Corps and Reclamation O&M for Hydro Plants $241M (9%) Payments to Residential & Small Farm Consumers of IOUs $324M (12%) Transmission Purchases, Reserve/Ancillary Services $184M (7%) Fish and Wildlife Services $143M (6%) Other $125M (5%) Internal Operations Charged to Power Rates $109M (4%) Conservation Program (Expense) $71M (3%) Renewables Program $42M (1%) Long Term Generation Projects $25M (1%)

  42. Spokane Settlement • Background: • In the original PFR forecast last year there was an estimate for costs associated with the Spokane Settlement proposal. In the final PFR report it was decided to remove the forecast amount out of the revenue requirement since it had not passed the House and Senate at that time. However, this issue is being discussed in the House and Senate again this year so there is still a chance the legislation will come to pass. BPA committed to revisit this issue in the PFR II in order to give participants a feel for what is happening with the legislation. • Current Update: • Legislation introduced in House and Senate. • House and Senate committees agreed to common bill. • House passed the bill; House bill now at the Senate, though is being held.

  43. Spokane Settlement • Initial Proposal treatment of the potential Spokane Settlement: • The revenue requirement assumed a forecast of $0 M in the initial proposal • The forecast amount for the Spokane Settlement is calculated as 28.3% of the Colville Settlement amount. There is a floor and ceiling amount to this calculation • The Colville settlement amount is based on the output from Grand Coulee valued at an amount as stipulated by the original legislation and includes a ceiling and floor. • The risk section (NORM) assumed a 60% probability of occurrence for the Spokane Settlement when it modeled this risk

  44. BPA Financial Disclosure Information • The information on the effect on the revenue requirement is a derived estimate for presentation purposes and may not be found in Agency Financial Information releases but is provided for discussion or exploratory purposes only as projections of program activity levels, etc. Such information should be used only for the purpose for which it was provided and should not be recommunicated by the recipient without the foregoing qualification. • All FY ’06-’09 information was provided in January 2006 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 ’97-’05 information was provided in January 2006 and is consistent with audited actuals that contain BPA-approved Agency Financial Information.

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