Opportunity for Public Comment; Bonneville Power Administration's Policy Proposal for Power Supply Role for Fiscal Years 2007-2011

AGENCY:

Bonneville Power Administration (BPA), Department of Energy.

ACTION:

Notice of Regional Dialogue policy proposal and opportunity for public comment.

SUMMARY:

BPA is publishing a policy proposal stating how the agency proposes to market power and distribute the costs and benefits of the Federal Columbia River Power System (FCRPS) in the Pacific Northwest for Fiscal Years (FY) 2007-2011. This proposal is intended to clarify BPA's obligation to supply power to its regional power customers and guide BPA in developing and establishing its firm power rates in the future. Clarifying these issues will create valuable certainty for customers over their BPA power supply. Final policy decisions will be made by BPA in December 2004 after all public comments have been reviewed.

DATES:

Public comments will be accepted through September 22, 2004. Public meeting dates are included in the SUPPLEMENTARY INFORMATION section below.

ADDRESSES:

Written comments should be submitted to Bonneville Power Administration, P.O. Box 14428, Portland OR 97293-4428. Comments can also be sent via e-mail to comment@bpa.gov or submitted on-line at http://www.bpa.gov/comment. The proposal is also available at http://www.bpa.gov/power/regionaldialogue. Helen Goodwin, Regional Dialogue project manager, is the official responsible for the development of the Regional Dialogue proposal.

FOR FURTHER INFORMATION CONTACT:

Helen Goodwin, Regional Dialogue project manager, at (503) 230-3129.

SUPPLEMENTARY INFORMATION:

Schedule of public meetings:

1. August 17, 2004, 6 to 8 p.m., Seattle, Wash.—Mountaineers Headquarters, Olympus Room, 300 Third Avenue West.

2. August 19, 2004, 6:30 to 8:30 p.m., Eugene, Ore.—Eugene Water & Electric Board, 500 East 4th Avenue.

3. August 26, 2004, 6 to 8 p.m., Spokane, Wash.—Airport Ramada Inn, 8909 Airport Road.

4. August 31, 2004, 6 to 8 p.m., Boise, Idaho—Boise Centre on the Grove, 850 W. Front Street.

5. September 9, 2004, 6 to 8 p.m., Portland, Ore.—East Portland Community Center, 740 SE 106th Avenue.

6. September 15, 2004, 5 to 7 p.m., Kalispell, Mont.—WestCoast Kalispell Center Hotel, 20 North Main Street.

Any changes or additions to this meeting schedule will be posted on BPA's Regional Dialogue Web site at http://www.bpa.gov/power/regionaldialogue.

Table of Contents

I. The Origins of Regional Dialogue

II. Scope of the Proposal

III. Council Recommendations on BPA's Future Role

IV. Link to FY 2007-2011 Strategic Direction

A. The Report to the Region

B. Strategic Direction

C. Customer and Stakeholder Comments on the Agency Vision

V. BPA Loads and Resources FY 2007-2011

VI. An Integrated Strategy for FY 2007-2011

A. FY 2007-2011 Rights to Lowest-Cost Priority Firm (PF) Rate

B. Tiered Rates

C. Term of the Next Rate Period

D. Service to Publics with Expiring Five-Year Purchase Commitments that Do Not Contain Lowest PF Rate Guarantee through FY 2011

E. Service to New Publics and Annexed Investor-Owned Utility (IOU) Loads

F. Product Availability

G. Service to Direct Service Industries (DSIs)

H. Service to New Large Single Loads (NLSL)

I. Service to Residential and Small-Farm Consumers of Investor-Owned Utilities (IOUs)

J. Conservation Resources

K. Renewable Resources

L. Controlling Costs and Consulting with BPA's Stakeholders

VII. Long-Term Issues

A. Proposed Long-Term Policy: Limiting BPA's Long-Term Load Service Obligation at Embedded Cost Rates for Pacific Northwest Firm Requirements Loads

B. Proposed Schedule for Long-Term Issue Resolution

VIII. Risk Analysis

IX. Environmental Analysis

X. Next Steps

I. The Origins of Regional Dialogue

BPA is engaged in the Regional Dialogue process as part of its effort to provide clarity around key issues the agency and region will face when the current rate period ends with FY 2006. BPA's immediate goal is to decide issues for the FY 2007-2011 period that prepare the way for setting rates for the next rate period while assuring that the agency's long-term strategic goals and its long-term responsibilities to the region are aligned.

BPA must make and carry out policy decisions that promote the development of a cost-effective electric industry infrastructure and protect the value of the existing Federal system for the region in the long run without shifting risk to U.S. taxpayers.

These decisions will provide customers greater clarity about their Federal power supply so that they can plan effectively for the future and make capital investments in long-term electricity infrastructure, if they so choose. This process and ongoing efforts within the Western Interconnection and the Pacific Northwest to develop resource adequacy metrics will provide necessary transparency to the region's load serving entities regarding the amount of resources needed to serve load. BPA's strategic interest is to improve this clarity soon to avoid creating significant risk for the region's ratepayers that would come from delaying the development of the necessary infrastructure. Delays could create imbalance between supply and demand, which could in turn cause excessive price levels and volatility.

The Regional Dialogue began in April 2002 when a group of BPA's Pacific Northwest electric utility customers submitted a “joint customer proposal” to BPA. This proposal focused on settling the outstanding litigation on the Residential Exchange Program Settlement Agreement signed in 2000, as well as on determining how to market Federal power and distribute the costs and benefits of the FCRPS for 20 years. Although BPA agreed with substantial portions of the proposal, there were also areas of disagreement, such as the methodology and magnitude of benefits potentially offered to investor-owned utilities (IOUs) for the benefit of their residential and small-farm consumers.

In June 2002, BPA and the Northwest Power and Conservation Council (Council) jointly initiated a public process regarding BPA's marketing of Federal power post-2006. In September 2002, several jointly sponsored public meetings were held throughout the region for interested parties to discuss their proposals and provide new ideas and suggestions. BPA and the Council accepted comments and proposals from all interested parties. This phase of the Regional Dialogue ended when the Council submitted final recommendations on “The Future Role of Bonneville” to BPA in December 2002.

In February 2003, faced with a continuing financial crisis, BPA announced that it would proceed with a rate-setting process for the Safety Net Cost Recovery Adjustment Clause (SN CRAC). Consequently, BPA decided that the Regional Dialogue discussions should take on a slower, more deliberate pace, focusing only on a couple of key items, such as the level of benefits for the residential and small-farm consumers of the region's IOUs, until the rate case concluded.

In a June 5, 2003, letter, the governors of the four Pacific Northwest states encouraged BPA and the Council to jointly restart the Regional Dialogue. In response, BPA and the Council hosted a series of informal meetings with customers and interested parties throughout the region in the fall of 2003. Shortly thereafter, the Council released a set of principles and an issue paper entitled “Proposed Council Principles for the Future Role of the Bonneville Power Administration in Power Supply” for public comment. Following the close of comment in December 2003, the Council held several workgroup meetings aimed at gathering input from customers and others to help guide its next round of recommendations on the future role of BPA in power supply.

Following conclusion of the workgroup meetings, the Council released in April 2004 its draft recommendations on “The Future Role of the Bonneville Power Administration in Power Supply” and took public comment. Those recommendations were finalized and sent to BPA in May 2004.

In February 2004, BPA sent a letter to the region updating BPA's plans for resolving Regional Dialogue issues. This letter included a plan to present this policy proposal to the region for comment by the end of June 2004.

II. Scope of the Proposal

BPA's current firm power rates expire at the end of FY 2006 while nearly all of BPA's regional power sales contracts continue through FY 2011. BPA believes its first priority in the Regional Dialogue must be to resolve policy issues that likely will influence the next rate case and which must otherwise be made before 2007. This is the focus of this proposal.

In the February 2004 letter, BPA identified issues that are a priority to resolve for the FY 2007-2011 period. While this Regional Dialogue proposal focuses primarily on the FY 2007-2011 issues, key long-term questions remain unanswered. BPA is committed to resolving the long-term issues soon after the conclusion of this current process. A proposed process and schedule for resolving these issues is included in Section VII.B. BPA is strongly motivated to meet that schedule with the greatest degree of regional alignment possible. However, even if regional consensus does not emerge, BPA is committed to resolving the longer-term issues of who has the obligation to serve. BPA intends to make decisions based on the schedule outlined in Section VII.B.

III. Council Recommendations on BPA's Future Role

BPA thoroughly examined the Council's recommendations as it developed this proposal. This review showed that BPA's proposal and the Council's recommendations differ relatively little where the two address the same issues. BPA has intentionally limited the scope of this proposal primarily to issues that have to be resolved for FY 2007-2011. Consequently, issues such as the long-term “allocation” of the system are not addressed. As already mentioned, BPA agrees with the Council over the importance of these long-term issues and proposes a schedule for their resolution in Section VII.B.

Overall, BPA and the Council agree on the overall goals of the Regional Dialogue process—resolution of BPA's long-term role in providing power to regional customers at the lowest embedded cost-based rate, and capturing that role in long-term contracts and rates as soon as possible to create a durable solution. This proposal is the first step toward meeting these goals.

IV. Link to FY 2007-2011 Strategic Direction

The financial impacts of the West Coast energy crisis of 2000-2001 led many utilities to examine their policies and approaches to their power supply. BPA is no exception. Over the past year, BPA has invested much time and effort in strategic planning. The agency is in the process of finalizing its strategic direction with emphasis on FY 2007-2011.

This re-examination of BPA's mission and values is, along with comments and advice from the Council, customers, and other regional stakeholders, informing the agency's approach to the Regional Dialogue process.

A. The Report to the Region

In early 2003, BPA initiated a detailed examination of the events that began in 2000 that led to the significant rate increases and deterioration of BPA's financial condition. On April 18, 2003, BPA released a Report to the Region that included lessons the agency had learned, with the intention of translating those lessons into future actions.

Among a number of other lessons, the report noted that the level of BPA's costs and risks are driven heavily by the load obligations BPA assumes. Meeting those obligations was a large driver of BPA's cost and rate levels. The report pointed out that the amount of risk (market volatility and uncertainty) to be managed in the region's power system has grown substantially in recent years, and the fraction of that risk that BPA can absorb has gotten smaller. The report also noted that BPA must avoid the need to acquire large amounts of power on short notice to meet demand. There were also a number of recommendations for process improvement in cost management, decision making, risk analysis, and communications that BPA has put into place agency wide and used in developing this proposal.

The Regional Dialogue proposal has been developed specifically with those lessons in mind, particularly to resolve the agency's load uncertainty as soon as possible and provide customers with the certainty they need.

B. Strategic Direction

The Report to the Region highlighted the need for BPA to have a clear and steady strategy and manage to clear objectives. In response, the agency devoted a significant amount of time in the last year to clarifying its strategic direction.

BPA's strategic direction establishes the agency's most important objectives and the actions that will help it manage to these objectives. The strategic direction calls on BPA to advance the Pacific Northwest's future leadership in four core values—high reliability, low rates consistent with sound business principles, responsible environmental stewardship, and clear accountability to the region.

It should come as no surprise that the subjects to be covered in the Regional Dialogue process are well represented in the agency's strategic direction, particularly with regard to BPA's role as a low-cost provider and for clear regional accountability. The strategic direction guiding this proposal includes:

1. Regional Infrastructure Development: BPA policies encourage regional actions that ensure adequate, efficient, and reliable transmission and power service.

2. Conservation and Renewables: Development of all cost-effective energy efficiency to meet BPA loads, facilitation of regional renewable resources, and adoption of cost-effective non-construction alternatives to transmission expansion.

3. Benefits to Residential and Small-Farm Consumers of IOUs: The post-2011 benefit that BPA provides to IOUs for their residential and small-farm consumers is equitable based on the Northwest Power Act.

4. Rates: BPA's lowest firm power rates to public preference customers are consistent with sound business principles, reflect the cost of the undiluted Federal Base System (FBS) and are below market for comparable products, are predictable, and have low volatility.

5. Service to Direct Service Industrial Customers (DSIs): Explore a post-2006 DSI service option with a known or capped value.

6. Regional Stakeholder Satisfaction: Customer, constituent, and tribal satisfaction, trust, and confidence meet targeted levels.

7. Management: Collaborative customer/constituent/tribal relationships are supported by managing to clear long-term objectives with reliable results.

8. Cost Recovery: Consistent cost recovery over time.

9. Treasury Payment: BPA will plan to achieve and maintain a Treasury payment probability (TPP) that is the equivalent of a 95 percent probability for a two-year period and 88 percent for a five-year period. Options for achieving this goal include, but are not limited to, Cost Recovery Adjustment Clauses (CRACs) and Planned Net Revenue for Risk (PNRR).

10. Ratepayer and Taxpayer Interests: FCRPS assets are managed to protect ratepayer and taxpayer interests for the long-term.

11. Best Practices: Best practices (with emphasis on cost performance and simplicity) are obtained in key systems and processes.

12. Risk: Risks are managed within acceptable bounds. An additional principle guiding the Regional Dialogue is:

13. Legal Criteria: Approaches or policy options should not require legislative change and should minimize legal risk.

C. Customer and Stakeholder Comments on the Agency Vision

In the spring of 2004, BPA publicly released information about its long-term strategic direction as a springboard for discussions with customers and other stakeholders. The issues addressed in the strategic direction, as mentioned above, serve as the foundation for the Regional Dialogue. Account Executives held informal meetings and conversations with customers and discussed and recorded their comments. Some customers, as well as other constituents, also submitted written comments.

In the process of developing this proposal, BPA analyzed and considered 388 comments related to Regional Dialogue issues. Many who commented said that allocation of the system is a high priority issue and that the appropriate timing is now. They cautioned that discussions regarding BPA's long-term obligation to serve at embedded cost rates for Pacific Northwest firm requirements loads and related decisions would be difficult, and their objections to tiered rates were much more frequent than support. Commenters said that any allocation should be done before entering into the process to tier power rates.

V. BPA Loads and Resources FY 2007-2011

In order to match BPA's firm power obligation for FY 2007-2011 to its resources, this discussion needs to begin with a clear understanding of BPA's current loads and resources.

For the FY 2007-2011 period, BPA projects that firm power sales obligations will exceed firm Federal resources, with the difference growing from a deficit of about 15 average megawatts (aMW) in FY 2007 to about 190 aMW by FY 2011. Although it will have to be carefully managed, a deficit of this size does not create the same degree of cost and rate risk exposure as that BPA faced in 2000-2001 when the agency was preparing to solve the 3,300 aMW deficit it faced for FY 2002-2006. Historically, the system has remained in balance either by BPA making power purchases or through customer load reductions consistent with then-effective contractual terms and conditions. The price of solving BPA's 3,300 aMW deficit has been a 50 percent increase in BPA's wholesale power rates.

BPA assesses its loads and resources in its annual Loads and Resources Study, or “Whitebook,” as well as in the forecasts used to set firm power rates. These studies, which are a compilation of load and resource projections, provide a synopsis of BPA's loads and resources analyses. They share three major interrelated components: (1) BPA's Federal system load forecast; (2) BPA's Federal system resource forecast; and (3) load and resource balances.

The Federal system load forecast is the forecast of firm energy sales that BPA expects to make during the FY 2007-2011 period. It comprises aggregated net requirements sales forecasts for public utilities and Federal agencies, DSI customers, IOUs, and other BPA contractual obligations.

The majority of BPA's public utility and Federal agency customers have contracts that continue through September 30, 2011. A small number of contracts terminate or contain off-ramps as of September 30, 2006. For this estimate, BPA assumes public utility sales to Block and Slice/Block customers will equal their current contractual amounts, including step-ups in 2007, and that BPA will continue to serve those loads during the FY 2007-2011 period. There are no sales to the DSIs and no deliveries of power to the IOUs assumed during the FY 2007-2011 period because contracts currently do not call for deliveries to any of these customers. In fact, recently signed agreements with the IOUs explicitly state that there will not be any power sales for FY 2007-2011.

The forecast of available generating and contract resources includes the output of Federally-owned hydro generation, non-Federally-owned resources (hydro, thermal, and wind projects), exchange energy associated with BPA's existing capacity-for-energy exchanges, power purchases, and other BPA hydro-related contracts. Firm hydro resources are based on 1937 critical water conditions under the 2000 Biological Opinion that was implemented December 20, 2000, and incorporates changes associated in hydro regulation 03SN67a and up to 172 aMW of hydro improvements by FY 2012. The thermal firm resource is Columbia Generating Station. Examples of non-Federally owned resources include the Foote Creek 1, 2, and 4, Stateline, Condon, and Klondike Phase 1 wind projects; Ashland solar; Wauna cogeneration and Cowlitz Falls and Dworshak hydro.

To calculate the BPA load resource balance, BPA compares Federal system firm energy loads with Federal system energy outputs for each month of the study period years. The results of this comparison yield the monthly and annual firm energy surplus or deficit of the Federal system.

VI. An Integrated Strategy for FY 2007-2011

A. FY 2007-2011 Rights to Lowest-Cost Priority Firm (PF) Rate

Most current 10-year Subscription contracts with public utility customers contain a guarantee that BPA will apply the lowest cost-based PF rates throughout the remaining term of the Subscription power sales contracts. Three five-year contracts also contain this 10-year guarantee.

Upon review, BPA believes this contractual guarantee is clear. Accordingly, even if BPA were to adopt a tiered-rate design during the term of the existing contracts, BPA would not apply a higher priced PF Tier 2 rate to the purchases of customers whose contracts contain the rate guarantee during the term of the contract.

B. Tiered Rates

BPA proposes in Section VII.A. a long-term policy to limit its sales of firm power to its Pacific Northwest customers' firm requirements loads at its embedded cost rates to approximately the firm capability of the existing Federal system. Administrator Steve Wright suggested in his December 9, 2003, letter to the Council that BPA believes tiered rates should be fully explored as a means to achieve that goal. In comments to the Council, many customers have voiced concerns regarding implementing tiered rates in the rate period starting in FY 2007. Most agreed with limiting BPA sales at embedded cost, but urged that new long-term contracts defining rights to the lowest embedded cost rate be developed before BPA puts tiered rates into effect. In its May 2004 recommendations “The Future Role of the Bonneville Power Administration in Power Supply,” the Council acknowledged that tiered rates would be the clearest practical indication of how BPA will be carrying out its role in the future. However, it went on to say, if BPA defines its role as the Council recommends, and if critical issues are resolved in a timeframe consistent with the Council's request that new contracts be offered no later than October 2007, then the Council would not press for tiered rates under the current contracts for the next rate period.

BPA is obligated to serve customer net requirements, even if that request is in excess of what the existing Federal system can supply. BPA believes tiered rates in combination with new contracts are a necessary part of the long-term solution to limit BPA's sales at embedded costs for Pacific Northwest firm requirements loads to the existing system. However, BPA also believes it is not critical to implement tiered rates in FY 2007, because BPA loads and resources are roughly in balance for the FY 2007-2011 period. Accordingly, BPA proposes to exclude tiered rates in its FY 2007 initial rate proposal. Instead, BPA proposes to explore tiered rates as part of an integrated long-term contract and rate solution that would implement the proposed long-term policy of limiting BPA sales at embedded cost for Pacific Northwest firm requirements loads.

C. Term of the Next Rate Period

Most of BPA's current power contracts are effective through FY 2011. BPA's current power rates are effective through September 30, 2006. In early 2005, BPA will begin rate case workshops in preparation for the FY 2007 rate case that will set rates for the next rate period. Based in part on suggestions from customers and others, BPA has already made a tentative decision to limit the duration of the next rate period to less than five years. The primary reason for doing so is to reduce the risk inherent in setting rates for longer periods of time, thus allowing BPA to set rates lower than otherwise would be the case and to reduce the need for rate adjustment mechanisms like the current CRACs. BPA is proposing to limit the next rate period to either two or three years. Before making a final decision on this, BPA would like to consider public comments. The following are some considerations on the length of the rate periods:

Two-year rate period (October 2006-September 2008): A two-year rate period would likely result in lower rates, and lessen the need for rate adjustment mechanisms due to reduced uncertainty. In Section VII.B., BPA proposes a schedule for developing new long-term power contracts, with the earliest effective date of those contracts projected at October 1, 2008. A two-year rate period would synchronize the start of these new contracts with the start of the subsequent rate period, both in FY 2009. However, proposing a two-year rate period is not without risk. Putting new contracts and new rates in place by FY 2009 will require a major effort in a compressed time frame by BPA and its customers. The formal rate case to support these new contracts would likely need to occur between January and August 2008. A separate rates process to define a long-term rate methodology may also be necessary. If new contracts are not in place by October 2008, but rates expire on that date, BPA would either have to extend then-effective rates or conduct a new rate case.

Three-year rate period (October 2006-September 2009): A three-year rate period would enable the Power Business Line's (PBL) rate period to coincide with the BPA Transmission Business Line's (TBL) rate period starting in October 2009, as requested by some customers and other interested parties. It would reduce the risk of not completing long-term contract negotiations on schedule and having to conduct a new rate case or extend rates. If BPA's long-term policy decision and subsequent contract negotiations are concluded earlier, BPA would have to replace those rates with new rates that reflect the new Regional Dialogue contracts.

D. Service to Publics With Expiring Five-Year Purchase Commitments That Do Not Contain Lowest PF Rate Guarantee Through FY 2011

The majority of BPA's public body, cooperative, and Federal agency customers signed 10-year Subscription contracts during the 1999-2000 Subscription period. However, seven public customers entered into five-year Subscription contracts, representing 307 aMW of load, expiring on September 30, 2006.

BPA assumes that these customers will request either an extension of their current contracts through September 30, 2011, or follow-on contracts. Three of the seven customers have contracts containing language that guarantees service through September 30, 2011, at the lowest applicable cost-based power rates provided under the applicable PF rate schedule. The remaining five-year customers have informed BPA that they would like BPA to offer them the lowest-cost PF rates through September 30, 2011. This would provide them with the rate certainty for FY 2007-2011 they are seeking.

Besides the five-year customers described above, four public customers signed 10-year contracts that contain five-year options, giving them the right to either remove or add load (i.e., PF off-ramp, PF on-ramp). These customers seek rate certainty for FY 2007-2011 for any purchases they elect to make under their options. The load associated with the five-year options is 524 aMW.

In addition, in 2002, BPA officially extended the United States Navy's five-year Subscription contracts for Naval Submarine Base Bangor, Naval Station Bremerton, and Naval Radio Station Jim Creek through September 30, 2011. Because the window for Subscription closed prior to the contract amendments, the Navy's contracts do not contain language that guarantees the lowest PF rates for the FY 2007-2011 period. The Navy has informed BPA that it would like BPA to apply the same rate treatment to the Navy that will be applied to the customers with five-year purchase commitments that do not contain the lowest PF rates guarantee.

Customers with five-year purchase commitments, as well as the United States Navy, are seeking clarity about post-FY 2006 rates, and BPA is seeking early load certainty from customers in order to facilitate better resource and rates planning. In addition, the agency is looking to create parity among all public customers by proposing to place the public customers with five-year purchase commitments that do not contain the lowest PF rates guarantee on equal footing with the 10-year customers from a rates perspective. Such alignment will facilitate BPA's move toward developing and offering new long-term contracts.

As a means of achieving the aforementioned goals, BPA proposes to offer all of the public customers with expiring five-year contracts that do not contain the lowest PF rate guarantee an amendment to extend the term of their existing contracts through September 30, 2011, which would make them consistent with the other 10-year Subscription contracts. The amendment would include language providing the same guarantee of the lowest PF rates (except for New Large Single Loads (NLSL)) as other customers have. The guarantee of lowest cost-based PF rates would also be extended to the United States Navy. In addition, BPA proposes to recalculate the firm power load net requirements of each of the affected public customers for the FY 2007-2011 period for purposes of load and resource planning, rate setting, and contract offers. BPA proposes to make such an offer well in advance of BPA's next section 7(i) power rate case. Public customers would have a 60- to 90-day period, specified by BPA, in which to accept BPA's offer. This window would close no later than June 30, 2005. This timeframe would allow BPA to incorporate the results of the net requirements calculation into the FY 2007 initial rates proposal. BPA is also proposing the offer be for the same power products and services as the customer currently purchases, as addressed in Section VI.F., Product Availability. Customers who choose not to accept the offer during this time frame may still request a new contract, but they will not be eligible to receive the lowest PF rate guarantee. The product choices available would be those described in Section VI.F.

BPA proposes similar action for public customers with expiring options for FY 2007-2011. BPA would offer each customer a contract amendment to provide an early opportunity to elect to cancel its PF off-ramps or on-ramps and add language that guarantees service at the lowest PF rates (except for NLSL), consistent with language in other current 10-year contracts. BPA would calculate the net requirements of those customers, reflect the amount where appropriate in the contract amendment, and provide service for the returning off-ramp or on-ramp load based on the results of the net requirements calculation. Again, customers would have to accept the offer within a 60- to 90-day period to be specified by BPA. As with the window for customers with the five-year contracts, this window would close no later than June 30, 2005.

If customers do not accept BPA's offer during the prescribed timeframe, they would be subject to the applicable rates determined in FY 2007, which will include a proposed Targeted Adjustment Charge (TAC) or its successor, reflecting the cost and risk entailed in delayed certainty about the size of BPA's purchase obligations for the rate period starting in FY 2007.

By calculating the net requirements of customers, particularly those with options affecting the second five years, it may be reasonable to expect a reduction in the amount of load BPA will be obligated to serve during FY 2007-2011. This should reduce the need for BPA to acquire firm resources on an annual basis to serve its firm load obligations, help prevent adding high costs to the FBS, and help lower firm power rates.

E. Service to New Publics and Annexed Investor Owned Utility (IOU) Loads

Selling power to new public utilities is consistent with BPA's mandate to encourage the widest possible use of Federal power. Since enactment of the Northwest Power Act in 1980, the agency has been obligated to sell power to serve the regional firm power requirements loads of public bodies (including new public utilities), cooperatives, and IOUs net of such entities' non-Federal resources used to serve their load. BPA is also authorized to sell power to Federal agencies in the region.

Over the last 20 years, BPA has supplied new public utilities with approximately 300 aMW of power. This section addresses the proposed conditions under which BPA would propose in its rate case to serve new public utilities (public body, cooperative, and Federal agencies) between October 1, 2006, and September 30, 2011, at the lowest PF rate. In addition, it addresses service to IOU loads annexed by public utility customers.

New Public Utilities: Under law and BPA policy, in order to receive service from BPA, entities that form new public utilities must meet BPA's Standards for Service criteria and request firm power service under section 5(b) of the Northwest Power Act. For purposes of the FY 2007-2011 period, BPA proposes that in order to receive power at the lowest PF rate, new public customers would need to meet these criteria prior to June 30, 2005. If these criteria are met, the customer would be eligible for future rate treatment comparable to other BPA public utility customers.

Conversely, BPA proposes that new public utilities which meet BPA's Standards for Service, and request firm power service from BPA after June 30, 2005, will be served at the PF rate plus a charge or rate that covers any incremental cost incurred by BPA to serve the new publics. The charge would be similar to the current TAC and would be applicable for the rate period that begins in FY 2007. Long-term applicability of a PF plus incremental cost-based rate to such new public utilities will be part of subsequent long-term Regional Dialogue discussions and future rate cases.

Annexed IOU Loads: To the extent an existing public utility requests firm power service for load that is annexed from an IOU, BPA proposes that the residential and small-farm load proportion receiving residential exchange benefits through the IOU will offset any applicable incremental cost charge, such as a TAC, in an amount equal to its proportionate share of benefits received from the IOU. BPA will continue to treat such annexed load as it does today under existing contract terms and conditions with its customers.

BPA has reviewed its contingent Subscription power sales contracts and has determined this proposal creates no impact on entities holding such contracts because these customers have contractual rights to qualify prior to a date certain. This proposal limits BPA's risk associated with new public customer loads by assuring that loads to be served at the lowest PF rate are known before rate case decisions are made. Commitment by a date certain provides earlier certainty about BPA's firm power obligation.

F. Product Availability

BPA is addressing which products it will offer its net requirements purchasers in the FY 2007-2011 period, specifically, what products customers can purchase in addition to or instead of the products currently being purchased in existing power sales contracts. Most BPA regional power sales contracts are effective through FY 2011, and the rest expire in FY 2006. BPA has also considered whether customers may decrease the amount of power they are obligated to purchase from BPA during FY 2007-2011.

To date, issues that are of concern to customers and other parties, as well as recommendations from the Council, focus on the following three questions:

1. Which products can customers with contracts that expire in FY 2006 purchase during this period?

2. Can customers with contracts that expire in FY 2011 switch products in FY 2007 or change the allocation of products they currently purchase?

3. Can customers with contracts that expire in either FY 2006 or FY 2011 acquire and use non-Federal resources to serve their firm loads and thereby reduce their net requirements service from BPA in the FY 2007-2011 period?

The Council recommends that BPA provide customers the opportunity to choose the products that best meet their needs.

Under existing contracts for service, BPA sells Full Service, Partial Service for customers with non-Federal resources, Fixed Blocks, and Slice. Partial Service is provided for customers with fixed resources and for customers with hydro resources dedicated entirely to serve load. BPA's proposal is as follows:

Products for Customers Whose Contracts Expire in FY 2006 or Are New Public Customers

BPA proposes that any customer whose contract expires in FY 2006 may simply request a contract extension with no product changes under the terms described in Section VI.D., above. Any new public customer or customer whose contract expires in FY 2006 and who elects to execute a new contract may select its choice of any of the following core requirement products—Full Requirements Service, Simple Partial Requirements Service, Partial Requirements Service with Dedicated Resources, and Block Service (with the optional feature of Shaping Capacity). The terms of the contract will be consistent with the terms described in sections VI.D. and VI.E., above.

No customers currently have the Complex Partial (Factoring) and Block with Factoring products. BPA does not intend to offer either of these products in future contracts because of the lack of interest shown and the expected complexity of administering and billing the products.

Product Switching or Changing the Allocation of Products Currently Purchased by Customers With Contracts That Expire in FY 2011

BPA has received indications that most customers whose contracts expire in FY 2011 want to keep their current product selections. Therefore, BPA does not see a need to offer contract amendments that would allow changes in the power products and services purchased by 10-year Subscription contract holders. However, a few customers have expressed interest in purchasing Slice in FY 2007 or in increasing or decreasing the amount of the current Slice contract amount.

BPA is very reluctant to deny requests to change Slice purchases when those requests come from customers who may feel strongly that it is in their strategic interest to make such a change. However, after extensive review and discussion of the issue, BPA believes it would not be prudent to propose a change in FY 2007 in the number of Slice customers or the Slice percentage sold. A primary reason for the proposal is the major importance placed by BPA and most customers on moving promptly to develop new long-term contracts and rates to implement the BPA power supply role proposed in this document. BPA is concerned that changing Slice elections by customers within existing contracts, and dealing with the associated inter-customer equity issues and technical issues, would be a complicated undertaking that would become a major diversion from the goal of new long-term contracts. The schedule proposed in this document creates a customer option to move to new contracts in FY 2009. BPA believes that focusing BPA and customer effort on meeting the schedule for those new contracts should be a higher priority than making adjustments to Slice purchases under existing contracts. Additionally, there is ongoing litigation pertaining to the annual true-up of the Slice product whose outcome will be uncertain for some time. BPA's view is that one outcome of this litigation could result in a significant cost shift from Slice customers to non-Slice customers. Increasing the amount of Slice purchases while such a cost shift risk exists is a significant concern. BPA therefore proposes no changes to the number of Slice customers or Slice percentage sold in FY 2007.

Customer Acquisition of Additional Non-Federal Resources to Reduce Net Requirements by Customers With Contracts That Expire in Either FY 2006 or FY 2011

BPA proposes to consider, on a case-by-case basis, requests from load-following customers to add non-Federal resources to their existing contract declarations. Such action could assist in relieving BPA's load-serving obligation post-2006 without increasing costs or risks for other customers. BPA will make such a determination at the time a customer makes its request.

For additional information on the products offered, please see BPA's Web site http://www.bpa.gov/power/psp/products/catalog.shtml. For wind integration, see http://www.bpa.gov/Power/PGC/wind/BPA_Wind_Integration_services.pdf.

G. Service to Direct Service Industries (DSIs)

DSI Subscription contracts expire September 30, 2006. The original 1,500 aMW of DSI contracts have been significantly reduced by load buy-downs, contract terminations, smelter bankruptcies, and other DSI financial difficulties. Only half of the original contracts are still in effect, and the highest monthly total for power provided under these agreements has never exceeded 400 aMW.

The Council recommended that BPA continue to provide some service to the DSIs. The Council suggested “there may be an opportunity to provide a limited amount of power for a limited duration under specified terms and conditions. If power is to be made available to DSIs, the amount and term should be limited, the cost impact on other customers should be minimized, and Bonneville should retain rights to interrupt service for purposes of maintaining system stability and addressing temporary power supply inadequacy.” BPA also continues to be interested in finding ways to provide limited service to DSI customers but recognizes that the agency's ability to affect the viability of the aluminum industry in the Pacific Northwest continues to be greatly limited by other factors beyond BPA's control. Global aluminum markets continue to make Pacific Northwest DSI economics appear highly challenging. These global markets and the construction of new, efficient, lower-cost smelters elsewhere in the world have pushed Pacific Northwest smelters from their former role as base-load plants to either swing plants or worse, excess capacity.

Although BPA has no statutory obligation to serve the DSIs, it recognizes that the DSIs have been an important part of the Pacific Northwest economy for decades. BPA is committed to exploring DSI service options that would result in a known, or capped, cost to other Federal power customers. BPA proposes providing up to 500 aMW worth of service benefits to DSIs. Under this proposal, any benefits would be targeted to DSIs that are creditworthy and have fully met their obligations under their Subscription contracts. BPA proposes providing these benefits only if such actions actually enable aluminum production and maintain Pacific Northwest jobs.

Within these proposed boundaries, BPA continues to look at a number of alternatives for continuing service to the DSIs as explained in the following paragraphs.

Financial Incentive to Operate: BPA is examining offering eligible DSI loads a defined and limited financial incentive to operate. This is the agency's current preferred approach. This benefit would be paid based on each eligible DSI demonstrating that it has used power purchased from the market to produce its product. To implement this, BPA would need to be assured that the cost impact on its other customers would be roughly no greater than if BPA had exercised its discretion to serve the DSI customers directly. This approach would allow eligible DSIs to make their own operating decisions recognizing the availability of the financial credit from BPA. It eliminates the direct sale of Federal power to the DSIs and, thereby, the associated credit and “take-or-pay” issues for all parties.

Continue Industrial Power (IP) Service: Providing IP power would appear not to meet BPA's principle of finding an alternative with a known or capped cost because the approach would require augmentation of the BPA system at an unknown cost. If, however, the cost could be fixed and limited in an acceptable fashion, then this alternative may hold promise.

Surplus Firm Power: BPA has explored ways to serve the DSIs with surplus firm power. Efforts to date have not found a product that appears to make economic sense for the smelters. The shape of BPA's surplus relative to the flat load of the DSIs and the fact that the smelters need a steady power supply do not align well. Finding a viable surplus product at a sufficiently low price is particularly difficult when coupled with the reality that smelter operations incur significant costs when they shut down and start up. In addition, getting power to DSIs could be challenging since BPA's Pacific Northwest public customers have priority access to BPA's low-cost surplus.

Credit Support for New DSI Generating Resources: The argument that is made for credit support from BPA is that it would enable smelters to operate without further reliance on power from BPA. With this option as well, BPA would need to be assured that the cost impact on its other customers would be roughly no greater than if BPA had exercised its discretion to serve the DSI customers directly. Credit support could be structured to cap and limit BPA cost and risk, though it would carry significant market and transactional risk to BPA, up to these limits. However, the cost of new resources continues to be much higher than what is needed for profitable smelting. Efficient gas-fired combustion turbines produce power at prices that appear too high under expected future natural gas, alumina, and aluminum market prices.

BPA is interested in public comment on whether BPA should continue to offer service to DSIs and whether the agency's current preferred approach is the way to deliver such benefits. BPA is also interested and willing to explore other ideas to provide qualifying DSIs benefits at a known or capped value that would be roughly no greater than if BPA had exercised its discretion to serve the DSI customers directly.

H. Service to New Large Single Loads (NLSL)

In June 2001, BPA opened a public process on three specific issues regarding BPA's NLSL policy. Two of the issues, transferability of Contracted For Committed To (CFCT) status and closing of the window for applying for CFCT status were subsequently resolved in a BPA record of decision (ROD) signed March 27, 2002. A decision on the third issue of transferring former DSI load to a preference customer in 9.9 aMW increments was postponed. BPA stated that this issue needed more debate on a broader scale and that it would be decided within the Regional Dialogue process.

The specific DSI NLSL policy issue raised was “whether BPA should change its NLSL policy to allow current and former DSI customers' production load served at BPA's IP rate, or any other rate, to transfer and receive power service in 9.9 aMW increments from a public body, cooperative, or Federal agency customer with power purchased at BPA's PF rate.”

This issue arose in part because two BPA preference customers with DSI plants in their service territories expressed the view that they should be able to acquire an additional 9.9 aMW of BPA power per year at the PF rate to serve local DSI plant production load. One utility in late 1999 began serving 9.9 aMW of DSI plant load by entering into a contract with the DSI that limited the amount of utility-provided service to 9.9 aMW. (The remainder of the DSI load was served with other contract resources.)

BPA and the utility disagreed on whether the applicable BPA wholesale rate was the PF rate or the New Resources (NR) rate. The question of which rate applied had no financial consequence prior to October 1, 2001, because during the 1996 rate period the PF rate was equal to the NR rate. The utility, the DSI involved, and BPA subsequently entered into a “standstill” agreement pending completion of a BPA DSI NLSL policy review that would establish which rate was applicable to DSI load transferred to local utility service in 9.9 aMW increments.

BPA proposes to continue its current NLSL policy with regard to a DSI transferring service to a local utility in 9.9 aMW increments. Any DSI load transferred to local utility service would be a NLSL and subject to the NR rate if served with Federal power unless the DSI qualifies for the cogeneration and renewables exception described below.

Besides affirming its current NLSL policy with regard to DSIs transferring service to a local utility in 9.9 aMW increments, BPA proposes to adopt an on-site cogeneration and renewables exception to its NLSL policy based on a similar exception contained in the 1981 BPA Utility Power Sales Contracts.

Section 8(e) of the 1981 Utility Power Sales Contracts stated, “If a Consumer of a Purchaser provides a renewable or cogeneration resource to serve all or a portion of a load associated with a facility which would otherwise be a New Large Single Load, and thereby reduces the demand on the Purchaser, that portion of such load on the Purchaser, if any, shall not be a New Large Single Load, unless the load or portion thereof on the Purchaser is 10 aMW or more; provided, however, that if a Consumer sells, displaces or removes a resource or portion thereof from service to the Consumer's load at such facility, all such load shall be a New Large Single Load. * * *”

BPA proposes the exception be restricted to renewables and on-site cogeneration. Providing this exception would allow former DSI load to take a total of 9.9 aMW of service from a local utility at the PF rate if the rest of its plant load was served by renewables or on-site cogeneration. This may make it economically feasible for some DSI load to operate while limiting the amount of former DSI load that could be served at a PF rate. It also supports the development of cogeneration and renewable resources.

I. Service to Residential and Small-Farm Consumers of Investor-Owned Utilities (IOUs)

BPA is obligated to implement its Subscription contracts through FY 2011. These contracts implemented BPA's 1998 Power Subscription Strategy, which BPA designed to provide an equitable distribution of the benefits of the FCRPS throughout the region.

The Subscription contracts require BPA to provide 2,200 aMW of power or financial benefits to the residential and small-farm consumers of the region's six IOUs during FY 2007-2011. BPA recently signed agreements with all six regional IOUs that provide certainty in the amount and manner that benefits will be provided to their residential and small-farm consumers under their Subscription contracts. These agreements provide certainty by defining benefits as financial payments and not power deliveries, defining a mark-to-market methodology that uses an independent market price forecast in calculating the financial benefits; and, establishing a floor of $100 million and a cap of $300 million per year for these financial benefits.

BPA expects this approach will successfully implement the Subscription contracts. However, these agreements are under legal challenge. Since a fundamental goal of this Regional Dialogue proposal is clarification of BPA and customer load obligation for the FY 2007-2011 period, BPA seeks to clarify how it will proceed if the new agreements were set aside. Accordingly, in the event a court sets aside the new agreements and amendments but leaves the underlying Subscription contracts in place, BPA will notify the IOUs that BPA will exercise its Subscription contractual right to provide financial benefits and not power benefits during FY 2007-2011 under those contracts. In such an event, the financial benefits will continue to be based on a forecast of the market price of power developed in the BPA rate case. If the Subscription contracts are successfully challenged in court, the agency will follow the court's instructions in negotiating new contracts under the Northwest Power Act.

As indicated, BPA proposes to provide financial benefits rather than physical power to the residential and small-farm consumers of the region's IOUs for a number of reasons. BPA hopes that clarifying now which entity is responsible for acquiring resources to serve the IOUs' load will help spur development of regional infrastructure. This need for certainty supports BPA's current decision to exercise its contractual right to provide financial benefits rather than physical power instead of waiting until October 1, 2005, to make that decision as allowed by the Subscription contracts. In addition, BPA is seeking to minimize the acquisition of additional amounts of power that could result in an increase in the average cost of the existing FBS resources. Providing financial benefits eliminates the need and associated risk of BPA purchasing power in the market to support power deliveries to the region's IOUs. BPA believes this approach will continue to provide equitable benefits to the residential and small-farm consumers of the region's IOUs while balancing the costs to BPA's other customers.

J. Conservation Resources

Conservation has been a core resource for over two decades in the Pacific Northwest. BPA's programs have captured savings equivalent to a large nuclear power plant; and, consistent with guidance from the Council, conservation will remain a major portion of the agency's resource portfolio in the future.

Continued commitment to conservation is consistent with the priority outlined in the Northwest Power Act to increase the efficiency of all electric energy consumption. Further, BPA's support of conservation has been essential to helping maintain the necessary regional infrastructure to ensure energy efficiency programs are successful.

While there has been much discussion of how conservation development might be regionally structured for the post-2006 time frame, BPA has not determined what the specifics will be. Similar to the recommendations made by the Council, BPA proposes five principles to guide development of the specific elements for conservation. These general principles are:

• Use of the Council's plan to identify the agency's share of cost-effective conservation. BPA has been working closely with Council staff to ensure those targets are a reflection of the true cost-effective conservation potential in the region.
• The bulk of the conservation to be achieved is best pursued and achieved at the local level. There are some initiatives that are best served by regional approaches (e.g., market transformation through the Northwest Energy Efficiency Alliance (NEEA)). However, the knowledge local utilities have of their consumers and their needs reinforces many of the successful energy efficiency programs being delivered today.
• To contribute to meeting the financial challenges facing the region, BPA will seek to meet its conservation goals at the lowest possible cost and lowest possible rate impacts. While only cost-effective measures and programs are a given, the region can benefit by working together to jointly drive down the cost of acquiring those resources. For example, Conservation and Renewables Discount (C&RD) reporting to date indicates a cost for installed conservation measures in the range of $2.2 million per aMW while Conservation Augmentation (Con Aug) is averaging about $1.3 million per aMW versus NEEA programs, which are costing just under $1 million per aMW. Regarding the C&RD conservation costs, the $2.2 million figure excludes the customers' low-income expenditures claimed under the program and is an average cost reflecting that some utilities are booking conservation measure savings at a rate of $4 million per aMW. The wide variance in cost per aMW offers a significant opportunity for the region to pursue an important cost-saving option.
• BPA funding for local administrative support to plan and implement conservation programs has been essential. In the future, this support should be retained, with the appropriate level of funding open for discussion.
• Financial support for education, outreach, and low-income weatherization are important initiatives that complement a complete and effective conservation portfolio. However, these types of programs often yield no measurable savings or considerably more expensive energy savings (e.g., low-income weatherization). These program efforts have been successful and should continue to be funded.

These principles are consistent with Council recommendations. However, there is a need for significant detail to be developed before these principles can be transformed into a specific program structure that best serves the region. BPA envisions some form of collaborative planning process in which experienced individuals can develop a fully defined proposal for conservation that can then be brought to the entire region for consideration. This joint planning process can accomplish the blending of appropriate policy guidance with the flexibility to ensure conservation can meet the huge variance of conditions and needs that exist in the region.

The C&RD and Con Aug, complemented by regional initiatives such as NEEA, may provide a solid foundation for establishing viable program elements so the region can be effectively served going forward.

Finally, as BPA pursues opportunities to reduce long-term costs to ratepayers, conservation, as well as other demand side management options, will be carefully considered as part of the solution to transmission constraints. Conservation can be part of a Non-Wires Solution, which will not only provide low-cost power resources, but also will reduce or defer the need for transmission construction.

K. Renewable Resources

A key purpose of the Northwest Power Act is to “encourage, through the unique opportunity provided by the FCRPS, the development of renewable resources within the Pacific Northwest.” In meeting this purpose, BPA is to consider cost-effective renewable resources before acquiring other conventional resources while fulfilling its obligation to serve its customers' regional firm power loads.

In recent years, BPA has supported a range of renewable research and development (R&D) activities. BPA currently purchases 198 megawatts (MW) of output from new renewable resources to serve regional firm power load. Going forward, BPA proposes to engage in an active and creative facilitation role with respect to renewable resource development. This signals a move away from large-scale renewables acquisition toward a greater focus on finding ways to reduce the barriers and costs interested customers face in developing and acquiring renewables. As an added benefit, BPA believes its facilitation role would also help non-BPA customers develop renewable resources in the region. This direction is consistent with several of BPA's major strategic objectives.

Facilitation Options: There are many tools available to BPA to help facilitate the development of renewable resources in the region. BPA proposes to use a combination of these tools and asks for input as to which set of tools would best accomplish BPA's facilitation goal, within the financial limits described below. The tools BPA sees as being available include the following:

Integration services: BPA recently developed two new wind integration services in the spirit of regional facilitation. These services, and other intelligent and prudent uses of the flexibility of the Federal hydro system, will serve as the centerpiece of a renewable resources facilitation effort. BPA also intends to work with regional stakeholders to reduce transmission barriers facing renewable resources.

Transmission system improvements: Another option is participation in regional efforts to construct strategic transmission lines to foster the development of the region's excellent wind resources as well as finding ways to make more efficient use of existing transmission infrastructure.

Rate Discount: Approximately 30 customers devoted a portion of their C&RD funds to renewables in this rate period. Continuing such a rate discount mechanism is another facilitation option.

Limited Acquisition Role: Temporary acquisition of output from a renewable energy project as an “anchor tenant” for such projects is another facilitation option. However, it should be noted that among various options available to help facilitate renewables in the region, direct acquisition places the greatest financial demands on BPA and would be subject to rigorous financial and risk tests before approval.

BPA will apply a careful cost-effectiveness screen in considering which of the above-mentioned facilitation actions receive the most emphasis. The goal is to maximize the ratio of new megawatts installed per dollar spent. BPA will also consult with regional stakeholders as it considers facilitation options.

Program Funding: Consistent with its current approach, BPA proposes to continue to support its renewables program up to a net cost of $15 million per year. Calculation of net cost is the actual cost of all acquisition of current and any future renewable energy, plus internal support costs, less the value of energy produced by the renewable resources based on the long-term cost of power from a combined-cycle natural gas-fired power plant, and minus Green Tag and green energy premium revenues. The costs associated with the $15 million renewables fund would be recovered through BPA's firm power rates. In addition to the $15 million annual net cost, during the current FY 2002-2006 rate period, $6 million per year has been available for renewables development through the C&RD program. BPA proposes to continue this level of support in addition to the $15 million net cost, though as described above, BPA has not concluded whether a C&RD-like mechanism is the best vehicle for use of this level of financial support. BPA's renewables facilitation activities will be subject to a risk review to ensure that they are consistent with the agency's financial objectives.

L. Controlling Costs and Consulting With BPA's Stakeholders

BPA seeks to renew and strengthen its role as a reliable business partner with its customers and to maintain the trust and confidence of the region's stakeholders. A key feature of this effort is designing structures and mechanisms that allow stakeholders to provide input on long-term cost control and on revenue requirements and especially before starting the FY 2007 rate case. BPA believes these actions directly support several of the agency's strategic objectives, including:

• Best practices (with emphasis on cost performance and simplicity) are obtained in key systems and processes,
• Increased transparency in processes, decisions, and performance, and
• Customer, constituent, and tribal satisfaction.

During the last two years, BPA has responded to customer and constituent requests for greater transparency in its finances and decisions that affect BPA's ability to control its costs. BPA has participated in the customer-organized Customer Collaborative process, which was set up to provide greater insights into BPA's financial performance, cost drivers, challenges, and controls. BPA also created, at the request of customers and constituents, the Power Net Revenue Improvement Sounding Board. The Sounding Board is a broad cross section of customers and constituents that provided BPA with input on how best to achieve $100 million in cost reductions and revenue enhancements during FY 2004-2005. BPA has been conducting regular monthly technical updates on financial conditions for customer staff.

Moreover, during the last year, BPA improved its financial reporting. These efforts include creation of new standardized financial reports and implementation of a new financial disclosure policy.

BPA proposes to continue the mechanisms described above. Forums such as the current Customer Collaborative structure, as an executive-level customer-led forum, is an effective way for customers to be at the table to discuss BPA's financial performance and related issues (for example, the effects of debt optimization on the power function or of new security cost increases). Likewise, the Power Net Revenue Improvement Sounding Board has served well as a means for providing leaders of both customers and non-customers better insight and input into BPA cost control efforts. The monthly technical financial update meetings with customers and constituents have been useful, and BPA is willing to continue such forums.

For the term of existing contracts (through FY 2011), or until new contracts go into effect if that is earlier, BPA proposes to continue to focus on non-contractual means that promote transparency under BPA's financial disclosure policy, allow for public input on agency costs and demonstrate management of those costs. The additional actions being proposed are described below.

Collaborative Forums: BPA is willing to participate in collaborative forums with both customers and non-customers in a structured approach similar to the Sounding Board and current Customer Collaborative. BPA believes that such forums should include the following:

1. Stated expectations, purpose, membership appointment, attendance, procedures, schedules, norms, roles and responsibilities, and disclosure requirements.

2. A focus on both standard routine financial updates and specific discussions aimed at understanding cost structure and drivers.

3. A summary of standardized information each quarter on how the effects of risk were factored into decision making.

4. As desired by the Collaborative participants, discussions aimed at understanding and providing individual participant input to specific issues BPA faces.

Financial Reporting with Customer and Constituent Input: BPA intends to make further advancements in its external financial reporting in order to increase awareness and understanding of BPA's financial performance by both experts and laypersons. Such information will also be posted on BPA Web sites.

Business Process Improvement: BPA also expects to develop and implement a plan to respond to the recommendations in the Business Process Improvement/Benchmarking initiative currently underway. Reports communicating BPA's progress against the resulting plan will be made available.

Power Function Review: Beginning in the fall of 2004, BPA plans to conduct a regional discussion regarding PBL program budgets and expenditures similar to the TBL's Programs in Review process. Toward that end, PBL will meet directly with customers and constituents and hold workshops as part of a Power Function Review public process. The goal of the Power Function Review is to allow for substantial review and public comment on PBL program levels prior to the next power rate case. Areas to be discussed include program challenges expected over the next seven years proposed program capital and expense levels, and program drivers.

Criteria for Public Comment on Cost Issues: In its effort to make cost decisions more transparent, BPA believes it is prudent to establish criteria by which to assess the need to subject pending discretionary BPA decisions that affect power costs to public review and comment.

First as a threshold, the decision or action must be a discretionary cost decision within BPA's control, not including short-term power purchases and associated revenues. It can include environmental, policy, or regulatory actions as well as new contracts, contract modifications, actions changing BPA's load-serving obligation, and BPA power marketing policies.

BPA will engage customers and other interests to determine specific criteria to be used to decide whether a discretionary action BPA is contemplating is appropriate for a public review and comment process and when BPA will inform the region of non-discretionary decisions. BPA believes that the factors below should be considered and addressed:

• Whether the cost action establishes a precedent.
• The effect on BPA, its customers, constituents, and other stakeholders.
• Whether and when public support is required for effective implementation of the cost action.
• The particular segments of stakeholders that can be expected to be interested in the cost action.
• The time available for public review and comment.
• The existence of concurrent public review and comment activities on similar or non-discretionary cost actions.

VII. Long-Term Issues

A. Proposed Long-Term Policy: Limiting BPA's Long-Term Load Service Obligation at Embedded Cost Rates for Pacific Northwest Firm Requirements Loads

Most of this proposal deals with FY 2007-2011 issues. However, BPA is also proposing a long-term policy regarding its load obligations. BPA's proposal is to limit its sales of firm power to its Pacific Northwest customers' firm requirements loads at its embedded cost rates to approximately the firm capability of the existing Federal system. BPA is further proposing a policy that firm power service beyond what the existing system can supply would be provided at a higher tiered rate that would reflect the incremental cost of purchasing power to meet those additional loads. BPA proposes to implement this long-term policy through new long-term contracts and rates on the proposed schedule presented in the next section. As stated in Section VI.B., Tiered Rates, BPA does not propose to implement tiered rates in FY 2007.

The agency is making this proposal for several key reasons:

• It would help reduce BPA's firm power rates by sharply limiting the past practice of acquiring power and melding its costs with the lower cost of the existing system, thereby “diluting” the low-cost existing system with higher-cost purchases.
• Greater assurance is needed that necessary electric infrastructure will be developed. Many BPA utility customers and other market participants are willing and able to invest in needed electric infrastructure, suggesting that the capability exists to supply the infrastructure without a continued buy-and-meld role for BPA. But these utilities need clarity about their load responsibilities versus BPA's if they are to move forward on infrastructure investment. This policy will help provide that clarity.
• A closely related benefit is that this policy will help utilities “see” market price signals as they make decisions about new resources, conservation investments, and load additions. This should lead to more efficient decision making throughout the regional electric industry.
• This policy does not prevent utility customers from continuing to rely on BPA to serve all their loads in the future if that is what they choose; consistent with BPA's legal requirement to do so.
• This policy will increase the certainty that BPA can repay the Federal taxpayer's investment in the Federal system by creating a higher likelihood that BPA rates stay well below market and fluctuate less with the costs of power purchases.
• There is strong support from BPA's utility customers for this policy direction. This is important because these utilities would be assuming more of the responsibility for new resource development over time.
• This policy direction is likewise consistent with the recommendations to BPA from the Council in its May 17, 2004, recommendations on “The Future Role of the Bonneville Power Administration in Power Supply.”

By itself, this policy is not enough to accomplish all the benefits listed above. It is only one step. For example, fully realizing those benefits requires that individual utilities know specifically how much power they will receive from BPA at the lowest embedded cost rate, and how much they will pay for increments beyond that amount. Creating that certainty will require subsequent development of new power contracts and rates. The proposed schedule for these additional steps, assuming the proposed long-term policy decision described here is sustained, is described next.

B. Proposed Schedule for Long-Term Issue Resolution

Although this proposal focuses primarily on resolving issues for the FY 2007-2011, BPA and the region have a strategic interest in resolving a number of key long-term issues. BPA is strongly inclined towards 20-year contracts assuming we can reach agreement on reasonable terms. This interest centers on providing BPA customers certainty over load service obligations and enabling customers and the market to respond with the necessary electric industry infrastructure investments. Other key strategic interests include general market stability, BPA risk management, and long-term assurance of funding to repay the United States Treasury. BPA's interest in resolving those long-term issues is shared by most BPA customers and with the Council.

To become effective, almost all the decisions must be captured in new long-term contracts and rates. There is a range of opinion within the region on what commitments and decisions can be made in contracts versus those that can be made in rates. BPA's view is that customers and BPA must work together to develop a logically-linked set of new contracts and rates, and that neither by itself will be sufficient to accomplish the long-term goals. This split between contracts and rates must be discussed and decided.

With respect to rates, BPA wishes to discuss with customers the merits of establishing a long-term rate methodology to accompany the contract. Another key question is when to execute new contracts and when to begin performance of the contracts. A key constraint is most customers have existing contracts that run through FY 2011. Many customers may be willing to sign new contracts well before FY 2011, but only so long as performance does not begin until their existing contract expires. BPA is also willing to explore other ideas to reach a goal of providing certainty to customers such as the option of offering contract amendments that would include a more limited list of issues, while providing customers with the load service certainty they are seeking.

Why BPA Believes These Issues Need To Be Addressed Now: It is in the strategic interest of BPA, BPA's customers, and the region as a whole to encourage regional actions that ensure adequate, efficient, and reliable transmission and power service. Waiting until near FY 2012 to create the clarity of obligations to develop resources would create a significant risk of waiting too long to create the necessary infrastructure. It would also create a longer period of risk to the region of losing the Federal system benefits and increase the risk that the taxpayers' investment in the Federal system would not be repaid in a timely fashion. Although executing contracts within the next few years to replace the current Subscription contracts carries significant risk, BPA is convinced that it is more risky to delay the necessary decisions. Nothing short of new contracts and rates will create sufficient clarity for individual utilities about their resource development obligations so that they can act with confidence on those obligations to develop the necessary electric infrastructure.

Next Steps: Given the complexity of developing new 20-year contracts, BPA needs to create a policy “blueprint” as soon as possible to guide development of new contracts and rates. The scope of this policy “blueprint” would be all the major policy issues needing resolution. Ideally, BPA's decisions on the issues will be informed by the broadest possible regional agreement. To that end, BPA intends to engage very actively with its customers, other stakeholders, and the Council to help achieve that agreement.

However, BPA has been encouraged by customers and the Council to establish and meet decision making deadlines and not defer decisions in hopes more time will yield consensus. Accordingly, after considering comment on the draft schedule below, BPA intends to establish a schedule and then make decisions on that schedule. The policy “blueprint” will also include a step for ensuring compliance with the National Environmental Policy Act (NEPA).

Proposed Schedule: BPA intends to begin now to operate on the schedule outlined below, subject to change based on public comment. The Council recommended a schedule that had new contracts offered in October 2007. This schedule has contracts offered almost a year earlier than that. This schedule is ambitious, but BPA agrees with the perspective of the Council and many customers that the region has a core interest in the earliest practical completion of this process.

This proposed schedule does not include rates decisions, which are a key component, because BPA wishes to have further discussion of the concept of a long-term methodology rate case. The final schedule will include rates milestones.

Challenges in Achieving Our Goal: BPA understands that achieving this schedule will be challenging. Challenges that both customers and the agency will have to manage include:

1. Ability of BPA, customers and other interests to find a solution to provide long-term benefits to residential and small-farm consumers to IOUs.

2. Ability to structure long-term contracts to protect taxpayer and ratepayer interests.

3. Managing changes to existing products and other contract terms and conditions that will allow meeting an aggressive schedule.

4. Managing the interaction of all power-related issues with the evolution of transmission issues including the TBL rate case and Grid West.

5. Developing regional resource adequacy metrics/standards to provide clarity and mechanisms to assure the development of needed electrical infrastructure.

6. Ability of customers and other interests to invest the necessary time, especially in view of the concurrent activity on BPA's FY 2007 power rate case and a variety of other issues.

7. Ensuring BPA and customers can administer new 20-year contracts for several years concurrent with contracts of customers who choose to retain their existing Subscription contracts through 2011.

8. Willingness of customers to sign new 20-year contracts before the supporting rate case concludes.

VIII. Risk Analysis

BPA undertook an analysis of risks associated with this proposal. The analysis identified the most potentially significant risks to be centered on load uncertainty and load placement and the absence of any effective ways to manage them given the statutory obligation to serve in the Northwest Power Act.

The amount and type of risks BPA takes in the area of load placement are central to development of the Regional Dialogue proposal. Augmentation, with its potential to leave BPA short in a volatile market, can and has led to significant rate increases. BPA's strategic direction, on the other hand, is heavily weighted toward stabilizing rates through a combination of better cost controls, risk management, and maintenance of key financial indicators such as Treasury Payment Probability (TPP). BPA found the primary areas of load uncertainty and potential risk concern to be service to new publics and service to the DSIs.

IX. Environmental Analysis

BPA staff is in the process of conducting a review under NEPA and its implementing regulations of the potential environmental effects of this proposal. As part of this review, BPA is evaluating how the proposal fits within BPA's Business Plan Final Environmental Impact Statement, DOE/EIS-0183, June 1995 (Business Plan EIS).

The Business Plan EIS evaluates the environmental impacts of a range of BPA business policy alternatives. This range includes BPA Influence, Market-Driven BPA, Maximize BPA Financial Returns, Minimal BPA Marketing, and Short-Term Marketing alternatives. The EIS also contains various policy “modules” for key issues such as rate design, DSI service, and conservation and renewables. These modules can be used to vary the alternatives. The alternatives are compared in terms of market responses, and the market responses are then used to determine potential environmental impacts. In addition, the Business Plan EIS identifies representative response strategies that could be implemented to address revenue shortfalls.

In August 1995, the BPA Administrator issued a ROD (Business Plan ROD) that adopted the Market-Driven Alternative from the Business Plan EIS. This alternative was selected because, among other reasons, it is the alternative that best allows BPA on balance to: (1) Recover costs through rates; (2) achieve strategic business objectives; (3) competitively market BPA's products and services; (4) continue to meet BPA's legal mandates; (5) meet legal mandates and contractual obligations; and (6) establish rates that are easy to understand and administer, stable, and fair.

An initial review of the Regional Dialogue proposal indicates that its potential environmental effects have been largely evaluated in the Business Plan EIS and that it would be consistent with relevant aspects of the Market-Driven alternative identified above. The proposal generally continues many of the business decisions and approaches taken by BPA in recent years that already have NEPA coverage, either through the Business Plan EIS itself or through subsequent RODs tiered to the Business Plan and ROD. For those areas in which the proposal may vary from current business decisions and approaches, the range of alternatives in the Business Plan EIS appears to provide coverage. Furthermore, implementation of this policy would be consistent with the response strategies identified in the Business Plan EIS and adopted in the Business Plan ROD. If further review confirms these consistencies, BPA likely would tier its policy decision under NEPA to the Business Plan EIS and ROD. All necessary NEPA review and documentation for this proposal would be completed prior to or concurrently with the Administrator's final ROD for this proposal.

X. Next Steps

The BPA Administrator intends to make final policy decisions for this part of the Regional Dialogue and sign a ROD in December 2004. Updated information will continue to be posted on BPA's Regional Dialogue Web site at: http://www.bpa.gov/power/regionaldialogue.