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NOTICE: NOTICES

ACTION: Power marketing plans:

DOCUMENT ACTION: Notice of proposed decision.

SUBJECT CATEGORY: Operational Alternative for Post-2004 Operations

DATES: To ensure they are considered, written comments from entities interested in commenting on this Notice of Proposed Decision must be received no later than 4 p.m., January 2, 2004. Western will accept written comments received via regular mail through the U.S. Postal Service if they are postmarked at least 3 days before such date. Entities are encouraged to hand deliver, use certified mail, or email to deliver comments.

DOCUMENT SUMMARY: The Western Area Power Administration (Western), a Federal power marketing administration within the Department of Energy (DOE), markets Federal power from the Central Valley and Washoe projects through the Sierra Nevada Region (SNR). Western published its Notice of Intent announcing the operational alternatives it was considering for post2004 operations in the Federal Register on June 24, 2003. Western held public meetings in July 2003 and accepted comments through August 8, 2003. Western reviewed the comments and assessed the feasibility of implementing each alternative to reach its proposed decision. Western's proposed decision is to implement a contractbased subcontrol area. Western will approach the California Independent System Operator (ISO) and the Sacramento Municipal Utility District (SMUD) to collect data and initiate discussions to develop a contract.

SUMMARY: Sierra Nevada Region; post-2004 operations; operational alternatives,

SUPPLEMENTAL INFORMATION

The selection of an alternative for post2004 operations is made under the authorities contained in the Department of Energy Organization Act (42 U.S.C. 71017352); the Reclamation Act of June 17, 1902 (ch. 1093, 32 Stat. 388) as amended and supplemented by subsequent enactments, particularly section 9(c) of the Reclamation Act of 1939 (43 U.S.C. 485h(c)); and other acts specifically applicable to the projects involved.

Public Process

Western published its Notice of Intent to consider certain post 2004 operational alternatives in the Federal Register (68 FR 37484) on June 24, 2003. The notice described each alternative and the factors Western would use in making a decision on which alternative to select. On July 9, 2003, Western held a Public Information Forum where each alternative was described, and the evaluation factors that would be used by Western when making its proposed decision were presented. Navigant
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Consulting, Inc., (Navigant) presented results from its comparative economic benefits study performed on behalf of the Bureau of Reclamation (Reclamation) and Western. Following the presentations, Western and Navigant staff answered questions from the attendees. A summary of the questions and answers at the July 9, 2003, Public Information Forum are at http://www.wapa.gov/sn/initiatives/post2004/opScenarios/July9P1responses.pdf. Western received additional questions
after July 9, 2003, and posted responses at http://www.wapa.gov/sn/initiatives/post2004/opScenarios/pifqas1.pdf .

Western held a Public Comment Forum in Folsom, California, on July 30, 2003, during which representatives from 12 entities commented on the proposed alternatives and decisionmaking factors. As individual stakeholders asked more detailed questions about Navigant's comparative economic benefit analysis, responses were prepared and posted to Western's external Web site throughout the comment period, which closed on August 8, 2003. Western received written comments from twentysix (26) different entities. Western posted the comment letters at http://www.wapa.gov/sn/initiatives/post2004/opScenarios/Comments080803/ on

August 13, 2003.

Throughout the public comment period, Western received and considered comments from existing power and transmission customers, joint powers agencies, water districts, irrigation districts, the ISO, the California Electricity Oversight Board, the ISO's Market Surveillance Committee, an investorowned utility, and an independent consumer group. The comments provided the unique perspective of each entity on the various alternatives, provided suggestions concerning the selection of an alternative, commented on the decisionmaking factors proposed by Western, and raised issues and concerns about implementing an operational alternative.

DecisionMaking Criteria

The criteria used by Western to reach its proposed decision are described in the June 24, 2003, Federal Register notice and were described in further detail at the July 9, 2003, Public Information Forum. The five criteria are flexibility, certainty, durability, operating transparency, and costeffectiveness.

Flexibility preserves the ability of SNR to join a Federal Energy Regulatory Commission (Commission) approved and certified Regional Transmission Organization (RTO) in the future and to adapt to ongoing changes in the electric utility industry. At the July 9, 2003, Public Information Forum, Western stated that whatever alternative was chosen, Western must retain its ability to be able to adapt its operations to future changes in the electric utility industry to minimize business uncertainty and impacts to Western's customers.

Certainty assures costofservice rates remain stable and predictable. Western further defined certainty at the July 9, 2003, Public Information Forum as having stable rates and charges so Western and its customers will be able to continue engaging in longterm business planning and to undertake prudent longterm commitments under a reasonable risk management planning horizon.

Durability assures operating protocols are well established and subject to minimal changes over time. Western stated at the July 9, 2003, Public Information Forum that this definition also included business processes and observed that major changes in business processes can significantly impair the efficiency and the ability of individual organizations to respond effectively because of the need for increased staffing and resources.

Operating transparency minimizes operating impacts to third parties. Western defined this factor as the ability for Western to change the operation of the Federal system with minimal impacts to third parties.

Costeffectiveness minimizes cost shifts and considers the relative cost and benefits to SNR's customers. Western stated at the July 9, 2003, Public Information Forum that cost effectiveness included the concept of ensuring that the overall cost of operation of the system and that the delivery of Federal power is kept as low as possible consistent with sound business principles.

Public Comments

Several comments indicated support for Western using the above criteria. Some comments also provided information concerning the relative weighting of the criteria that Western should use. The Transmission Agency of Northern California (TANC) commented that, given the relative instability of the electric utility industry, it is important for Western not to use costs as the only criteria for evaluating each post2004 operational alternative. Comments from other public agencies such as the Calaveras Public Power Agency, the Modesto Irrigation District (MID), the SMUD, the Silicon Valley Power (SVP), the Trinity Public Utilities District (TPUD), and the City of Redding, indicate a preference for selecting an alternative that is the most flexible, durable, and costeffective. The Lawrence Livermore National Laboratory (LLNL) commented that Western should further define the above criteria and provide interested parties with the relative weighting Western would use in selecting the operational alternative.

The ISO commented:

Western initially stated that the decision to form its own control area would be cost based. Now that the real impact of the costs of the various Market Plan options is being understood more clearly, the criteria for this decision seems to have changed. It wasn't until the June 24, 2003, Federal Register notice that the public learned for the first time that the factors that it [SNR] will use in its decisionmaking process are now flexibility, certainty, durability, operating transparency and cost

effectiveness.

The ISO and several other commentors also indicated concerns with grid reliability and complexity of operations and expressed a desire to include reliability as an additional evaluation category. Western did not receive any other suggested additions or changes to its proposed evaluation criteria.

Western's Response

The decisionmaking factors outline the business reasons Western must consider as it analyzes impacts associated with implementing each specific alternative. These business reasons include the ability to respond to industry changes, having a voice in its own future, providing customers with as stable an environment as possible as industry wide changes occur, and providing customers with products and services at the lowest possible rates consistent with sound business principles. Consequently, when making a decision on its future operations, it is not wise for Western to rely on a single factor. Thus, Western developed additional factors to allow it to continue meeting its statutory requirements and address its longterm strategic goals and objectives.

Western considered the request to include reliability as an additional evaluation category. Western decided not to include reliability as a separate evaluation category because, under existing Western Electricity Coordinating Council (WECC) and North American Electric Reliability Council (NERC) operating guidelines, Western must demonstrate negative impacts will either not occur or will be mitigated before a selected alternative is
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implemented. Because implementing an alternative must not decrease reliability under WECC/NERC operating guidelines, adopting this evaluation factor as an additional factor in this process is redundant.

Western assumes the ISO reference to Western's initial position that the decision on a post2004 operational alternative would be based only on cost was the result of a meeting between Western and the ISO in December 2002. At the meeting, Western indicated that any decision related to its future operational configuration would have to be supported by a business case. Western did not intend by its comments that its decision on a post2004 operational configuration would be based solely on cost.

In addition to the December 2002 meeting, Western participated with the ISO in a joint meeting with the Pacific Gas and Electric Company (PG&E), the Southern California Edison Company, and the San Diego Gas and Electric Company in February 2003. On April 8, 2003, Western met with the ISO to discuss the ISO's Metered Subsystem (MSS) proposal. At the time of these meetings, Western had not yet fully developed all of the evaluation factors it intended to use in its decisionmaking process.

An oral request by a representative from the LLNL to further define the criteria and to identify the weighting Western would use in making a decision was received at the July 9, 2003, Public Information Forum and considered. Western provided its definition of each criterion at the Public Information Forum and requested written comments on the definitions and the relative importance of each factor. Western did not receive any written comments on any specific modifications to the definitions and their relative importance.

Throughout the comment period, Western did not receive any adverse comments to its proposed evaluation criteria, although it received several requests to consider reliability as a separate factor. Western received many written comments supporting the criteria. Western concludes that the evaluation criteria and their respective definitions are appropriate. Therefore, the evaluation criteria are now final. This decision is based on Western's evaluation of the comments and the fact that Western did not receive a single written comment recommending any changes to the definitions of the existing factors.

The ISO and a number of other commentors expressed concerns that forming a new control area in northern California could compromise the reliable operation of the electric power grid. Specifically, these commentors expressed reservations that under a control area option, this option could increase the complexity of operations and potentially affect reliability. Western views these two concerns as implementation issues, rather than evaluation issues associated with forming a control area, and would be ordinarily resolved as part of the WECC and NERC certification process for formation of a new control area.

Implementing the Post2004 Power Marketing Plan

For Western to implement its post2004 Power Marketing Plan, significant investment in new business infrastructure and systems is necessary. This new investment in business infrastructure and systems is independent of Western's selection of a post2004 operational alternative. Since 1967, Western has operated as a separate, but integrated, subsystem of the PG&E system under the terms and conditions of Contract 14062002948A (Contract 2948A). PG&E has indicated it is unwilling to continue the terms of that contract. Western, in formulating the new marketing plan for the post2004 period, based on PG&E's positions, assumed that Contract 2948A would expire and services such as firming energy and ancillary services previously provided by PG&E would have to be either selfprovided or purchased in the market. Under Contract 2948A, PG&E provides these services and bills Western monthly. With the increased complexity of the markets and the need to schedule, account for, and settle transactions with the ISO on a 10 minute to hourly basis, Western needs to acquire replacement business systems to provide the same level of technical support for the post 2004 period now provided by PG&E.

One of the biggest changes that Western will face in implementing its post2004 Marketing Plan is that Western and its customers will be exposed directly to realtime changes in the market. Previously, under Contract 2948A, Western and its customers settled with PG&E on a monthly afterthefact basis. This change represents a significant departure from Western's current business practices and will require a substantial increase in work effort to implement Western's post2004 marketing program.

Western recognized its need for new business systems and infrastructure during the development of its new marketing plan. Western embarked upon an effort to identify the requirements to procure and install new business systems that would provide the needed tools for doing business in the business environment under the new marketing plan. The new systems needed to support the new marketing plan, regardless of which operational configuration is selected, include the Scheduling system, the Power Billing system, the Load Forecasting system, the Generation Optimization system, the Enterprise Architecture Integration system, the Meter Data Repository system, and the Settlements system.

The Scheduling system software supports two functional areas, the merchant function and the reliability function, because Western has chosen to follow the spirit and intent of the FERC Order Nos. 888 and 889, which require separation of the merchant function from the reliability function. The merchant function portion of the scheduling system enables the merchant to schedule transactions in the dayahead markets to deliver Federal power to Project Use loads and Preference Power customers, including the necessary transmission reservations required by Western's energy deliveries and Western's transmission customers.

The reliability function portion of the system provides for real time implementation of the dayahead schedules and any realtime modifications to schedules required to balance the control area, sub control area, MSS, or to accommodate schedule changes by Western's customers, including changes to transmission schedules. This new system is needed to accommodate hourly scheduling and accounting required under the new restructured energy markets, rather than the monthly scheduling and accounting previously required under the terms of Contract 2948A.

The Power Billing system allows Western to gather and process meter data and information from the Scheduling system, bill customers, and generate reports within administratively and contractually required time frames. The Power Billing system used by Western under Contract 2948A requires extensive modifications to accommodate hourly market settlements under current utility settlement standards. This major upgrade will allow Western to accurately bill and account for any of the alternatives under consideration.

The Load Forecasting system will enable Western's merchant function to forecast the load of customers who have requested portfolio management services under the Full Load Service option in the new marketing plan. As the portfolio manager for these
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customers, Western will need the ability to accurately forecast load requirements to optimize power purchases and minimize costs. Under Contract 2948A, since Western was not the load serving entity for these customers, it had no responsibility to meet customer loads other than to reduce load whenever energy deliveries to its customers exceeded Contract 2948A's maximum simultaneous demand level.

The Generation Optimization system is another new system that will enable Western and Reclamation to maximize the value of the hydropower generation from each Central Valley Project (CVP) power plant. Using the required daily water releases and hourly energy price forecasts, the Generation Optimization system will develop a water release schedule, which still allows Reclamation to meet its daily water delivery obligations, while simultaneously maximizing the value of the hydropower generation. When Contract 2948A expires, PG&E will no longer integrate CVP's hydropower generation with its own resource portfolio. Consequently, Western will need to have the optimization capability to maximize the value of the hydropower generated from the project's facilities.

The Enterprise Architecture Integration (EAI) is a software integration system and serves as the communications backbone for the different software packages. EAI allows data sharing and coordinates/ integrates the interaction between other software programs to develop reports and analytical studies that support daytoday business operations.

The Meter Data Repository system will allow Western to collect metered quantities from its delivery and interconnection points. Collecting this data will allow Western to analyze system performance and support its daytoday operations. The information stored in the data repository will be used by the maintenance, operations, and power billing functions to conduct daytoday operations to ensure that Western's transmission facilities continue to operate reliably and in conformance with all applicable NERC and WECC operating criteria. In addition, the metered data quantities will be used in Western's power rates function to support costofservice determinations.

The Settlements system will allow Western to keep track of its transactions with the ISO for each commodity purchased or sold in the ISO markets. Western's existing system is inadequate for post2004 operations since significant amounts of data need to be entered manually, and the current application is not easily integrated with other business applications/systems. A replacement system capable of automatically integrating data from other business information systems is required.

Western requires each identified system to meet the statutory obligations associated with implementing its post2004 Marketing Plan regardless of which operational alternative it selects. Because of the projected cost of the identified systems and resultant budget impact, Western worked with its customers during calendar year 2001 to secure additional funds to implement its new marketing plan. Customers recognized this need and provided more than $19 million to develop and implement these new business systems in fiscal years 20022004. Comparative Economic Benefits Study

Navigant prepared a comparative economic analysis of each post2004 operational alternative under consideration as part of this public process on behalf of Reclamation and Western. Navigant's initial comparative analysis showed that, of the three alternatives, the comparative net benefits of Western operating as either an MSS in the ISO control area or as a new control area were similar. Navigant's analysis indicated the Participating Transmission Owner (PTO) Alternative was the least costeffective option.

During the public comment period, the ISO and other commentors questioned some of the underlying assumptions used in the Navigant study. The ISO submitted a separate economic analysis showing the PTO and MSS options were the leastcost options. Navigant reviewed the assumptions used in the ISO's studies and the comments received on its study assumptions. As a result, a number of assumptions in Navigant's initial economic comparative benefits study were changed. The revised study indicates from an overall comparative economic standpoint, the PTO option continues to remain the least costeffective of the three alternatives being considered.

The revised comparative benefits study incorporated the following recommended changes to the assumptions: (1) Changing the treatment for selfprovided ancillary services to correct a misinterpretation of the ISO Tariff, (2) changing the operating reserve requirement under the Federal control area option to be the greater of 5 percent or the largest single contingency, (3) increasing Western expenses to escalate these costs at the rate of inflation, (4) changing the assumption to include all transmission revenues on the 94mile section of the Pacific AC Intertie (PACI) line between Malin and Round Mountain substations, (5) changing the assumptions regarding reliability services charges to eliminate charges for directconnected customer loads, and (6) changing the congestion charges applied to Western loads to reduce net congestion charges to 80 percent of the total charges.

The comparative economic benefit analysis estimated the comparative costs Western would incur under each proposed post2004 operating alternative over a 15year analysis period. The nominal values identified in the Navigant comparative economic benefit study were discounted at a Federal discount rate of 5.6250 percent to determine annualized benefits and costs. The annualized results of the study are summarized below:
Annualized Costs Associated With Implementing and Operating Each Post2004 Alternative [In millions of dollars] Participating Metered Federal transmission subsystem control area FCA option B FCA option C FCA option D owner option option option A Total Benefits............................................ 88.1 76.7 81.6 81.6 81.6 81.6 Total Costs............................................... 98.8 85.6 91.1 90.5 90.4 63.1 Net Benefits.............................................. (10.7) (8.9) (9.5) (8.9) (8.8) 18.5 Net Benefits Normalized to PTO Option..................... 0.0 1.8 1.2 1.8 1.9 29.2 [[Page 67421]]

The benefit calculation included estimates for sales of ancillary services, payments for transmission access charges, and transmission capacity sales. The cost components included estimates for the following ISO charges: ISO grid management charges, ISO transmission services, purchases of ancillary services from the ISO markets, transmission congestion charges, reliability services charges, energy imbalance/deviation charges, unaccounted for energy charges, neutrality charges, and grid operation charges. The study also includes Western's estimates of the capitalized infrastructure investment costs, annual operating expenses, and estimated transmission revenue requirements. The comparative economic analysis normalized the net benefits under each alternative against the cost of implementing the PTO option. Under this cost normalization approach, avoided costs associated with implementing each post2004 operating scenario show avoided annual costs of approximately $1.8 million for the MSS option and a range of $1.2 million to $29.2 million in avoided annual costs for the control area option. The cost avoidance range for the control area formation options result from decreasing ISO charges levied as more CVP customers join the new control area. The control area option analyzed four alternative scenarios. Scenario A assumed formation of a control area which included only the directconnected Reclamation Project Use loads. Scenario B assumed formation of a control area which included Scenario A and three directconnected Preference customers (Cities of Redding, Roseville, and Shasta Lake). Scenario C assumed all elements from Scenario B and added the following three other directconnected customers: the Turlock Irrigation District (TID), the MID, and the SMUD. Scenario D assumed the inclusion of all other Preference Power customers. The avoided costs increase across the scenarios as the fixed costs of forming and operating the proposed control area are spread over a larger base, and the amount of charges that control area participants are responsible for paying to the ISO decrease.

Excluding baseline operation and maintenance expenses, which would be the same under all post2004 operational alternatives, an estimate of annual operating expenses associated with each alternative was developed. The table below summarizes Western's estimated cost for each post2004 operational alternative.
Post2004 Operational Alternatives Cost Summary Estimated Annual Expenses [In millions of dollars] Participating Metered Federal transmission subsystem control area owner option option options (AD) Annual Operating Expenses....................................... 10.1 16.2 17.5 Annualized Capital Expenses:

Information Technology...................................... 2.8 2.8 3.2

Other Infrastructure........................................ 0.2 0.2 0.3

Substation Costs............................................ 0.0 0.7 2.8 Subtotal................................................ 3.0 3.7 6.0 Other OneTime Expenses:

Western Metering............................................ 0.0 0.0 1.0

Reclamation Metering........................................ 1.3 1.3 0.9 Subtotal................................................ 1.3 1.3 1.9

As discussed previously under the section entitled ``Implementing the post2004 Power Marketing Plan,'' much of the Information Technology infrastructure is required to implement the post2004 Power Marketing Plan. The only differences relate to capital investments required to support specific functionality in software, metering equipment, and substations. Operating expenses are significantly lower under the PTO option because there is no need to incur additional expenses in the maintenance and operations functions. Specifically, the MSS and control area options require two additional 24hour desks (Transmission Scheduling and Security and Automatic Generation Control) and additional expenses associated with maintaining facilities at Cottonwood (MSS Alternative) or Cottonwood and Round Mountain substations (Control Area Alternative) in the event Western is unable to successfully negotiate a contractbased path to the Pacific Northwest.

Although Western may ultimately need part of both Cottonwood and Round Mountain substations to implement the MSS Alternative, Western decided to take a more conservative cost approach for the initial comparative cost studies. If Western decides to implement the MSS Alternative in the future, Western may consider including Round Mountain Substation as a northern boundary point. Finally, the MSS and control area options require additional staff to handle settlements with the ISO. The Navigant study only analyzed the costs that Western would incur as a transmission provider under each post2004 operations alternative and, consequently, did not estimate the costs that individual customers would incur under each operating scenario.

Under the MSS and the control area formation options, Western assumed that to perfect its existing rights under Contract 1406200 2947A (Contract 2947A) it would be required to either acquire or invest in constructing alternative facilities at, or in the vicinity of, Cottonwood and Round Mountain substations. This would assure a contiguous path between Western's transmission system and the Pacific Northwest.

Executing a PTO agreement would result in blending the relatively low costs of Federal transmission facilities with the higher statewide costs of California's three investorowned utilities. This would result in an increase in costs to Western's Preference Power customers and Reclamation's Project Use loads without a corresponding increase in benefits.
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Description of Alternatives

The No Action Alternative

Under the No Action Alternative, Western would not undertake any actions before January 1, 2005, to establish a successor operational configuration or to develop and establish permanent new business arrangements with the ISO or PG&E, based on PG&E's position that it will not extend the terms of Contract 2948A. Under Reclamation law, Western is responsible for marketing and transmitting Federal power, but because it would not have a longterm business arrangement in place with the ISO or PG&E, Western would not be able to guarantee delivery of Federal power to Project Use loads from delivery points in the ISO control area.

Deliveries on the CaliforniaOregon Intertie (COI) lines could also be affected negatively as successor interconnection and/or transmission arrangements would not be in place. Western recognized the problems associated with this alternative before publishing its June 24, 2003, Federal Register notice. With no successor interconnection and/or transmission arrangements in place, under the No Action Alternative, the parties may have no other alternative but to seek the clarification and resolution of their respective interests through litigation. The June 24, 2003, notice stated:

Since a basis for transactions or business relationships necessary to carry out deliveries of power to customers does not exist, substantial business uncertainty would result. One or more of the parties could pursue litigation to determine the respective positions of Western and its individual customers, Reclamation, CAISO, and PG&E. This alternative creates business uncertainty and operational impediments which would result from not having successor agreements in place with PG&E and the CAISO.

Operating Scenario To Evaluate the No Action Alternative

Under the No Action Alternative, Western would be a contiguous electrical system with most of Reclamation's generation and Reclamation's single largest Project Use load (Tracy Pumping Plant), as well as some Preference customer loads directly connected to the Federal transmission system. Reclamation's offsystem generation at San Luis and New Melones would continue to operate under terms of existing contracts with PG&E that do not expire until 2016 and 2028, respectively. Western's northern boundary for its transmission system would be uncertain because of the lack of successor transmission arrangements to Contract 2947A at Round Mountain and Cottonwood substations.

Since Western would not undertake actions to implement a post2004 successor operational alternative, it would continue to reside within the ISO control area. Under the No Action Alternative, Western would not have longterm business arrangements that would allow it to deliver Federal power to Project Use loads, First Preference, and Preference Power customer loads not directly connected to Western's transmission system. Western would execute shortterm (nonfirm) transmission arrangements with the ISO, typically one day at a time, and would be subject to curtailments whenever congestion or other operational constraints arise.

Without longterm business arrangements, the ISO would not be obligated to provide services to Western. The converse is also true for Western. In the absence of longterm arrangements, Reclamation would not execute a Participating Generator Agreement (PGA) with the ISO. Revenues associated with generation or ancillary services excess to the needs of directconnected Project Use loads and Preference Power customers and sold to the ISO for its needs would not be available to Western. Western would exist within the ISO control area without specific boundaries, and without the ability to collect revenues associated with services provided to the ISO, or to deliver power on a sustained basis to meet Western's statutory and contractual obligations to offsystem Project Use loads, First Preference customers, and Preference Power customers, respectively.
Evaluation of the Flexibility Criteria Under the No Action Alternative

The No Action Alternative would give Western very little certainty in conducting its daytoday business operations. Without longterm business arrangements, Western would have to rely on shortterm arrangements with the ISO and others after January 1, 2005, to continue to do its business. Although these shortterm arrangements do not commit Western to a longterm relationship and allow Western to modify its operations, the arrangements are inherently unstable and create significant business uncertainty. Thus, the No Action Alternative does not meet the flexibility criteria.
Evaluation of the Certainty Criteria Under the No Action Alternative

The No Action Alternative does not assure a stable business environment for Western or its customers. With no longterm business arrangements, Western would have no basis for requiring the ISO or PG&E to deliver power to Western's offsystem Project Use loads or Preference Power customers served using the ISOcontrolled grid. On January 1, 2005, Western would not have negotiated longterm mutually beneficial business arrangements with the ISO or PG&E and, consequently, would have to undertake shortterm and potentially unstable business arrangements to deliver Federal power to Project Use and Preference Power loads not interconnected to the Federal transmission system. There would be no longterm rate certainty and, in the event rates increase faster than Western's ability to undertake changes through its formal ratesetting process, Western would face the potential of significantly reducing its power deliveries to avoid any potential violations of the Federal AntiDeficiency Act. The underlying uncertainty would also inhibit longterm business planning and, as a result, Western concludes that the No Action Alternative does not meet the certainty criteria.
Evaluation of the Durability Criteria Under the No Action Alternative

Under the No Action Alternative, Western would not have any operational protocols or business processes in place as of January 1, 2005. Effective this date, Western would put interim business procedures in place to continue operating in the ISO control area. Because shortterm arrangements are by their nature unstable, given the unique nature of the CVP hydropower system, unsettled rights on the COI, and the lack of a northern boundary for Western's transmission system, Western concludes that the No Action Alternative does not meet the durability criteria.
Evaluation of the Operating Transparency Criteria Under the No Action Alternative

Under the No Action Alternative, as of January 1, 2005, Western would have no longterm business arrangement with the ISO for operation of Western's transmission system within the ISO control area. Since Western would not have a longterm business arrangement with the ISO, every transaction would be accomplished on an interim, shortterm basis. Under this scenario, Western would not be able to guarantee delivery of Federal power to Project Use loads and meet its contractual commitments to First Preference and Preference Power customers to deliver energy to delivery points on the ISOcontrolled grid since [[Page 67423]]

it could buy transmission on only a nonfirm basis.

In addition to the uncertainty associated with Western's business relationship with the ISO, other uncertainties include the lack of successor transmission arrangements to Contract 2947A for continued transmission access to the PACI line, lack of successor operational arrangements (Coordinated Operations Agreement) for the coordinated operations of the threeline COI, and potential new business arrangements on the CaliforniaOregon Transmission Project (COTP). As a result of these business uncertainties under the No Action Alternative, Western cannot guarantee that its operations will not negatively impact the operations of third parties and, consequently, Western concludes that this alternative does not meet the operating transparency criteria.
Evaluation of the CostEffectiveness Criteria Under the No Action Alternative

Under the No Action Alternative, since Western will not have long term successor business arrangements with the ISO or others, the cost of conducting its daytoday business activities is highly uncertain. In addition, since no business relationship exists with the ISO, Western may not be able to realize the benefits of providing products for use in the ISO's markets. For instance, because of the lack of a longterm business arrangement such as a PGA, revenues associated with excess generation and ancillary services provided to, and which may be used by the ISO, may not be fully realized by Western. The ISO may furnish products and services to Western and its customers without a contractual relationship that would allow the ISO to bill Western for the use of such products and services.

Other business arrangements including the acknowledgment of Western's rights to transmission capacity on the PACI, potential new business arrangements on the COTP, successor arrangements for the coordinated operations of the COI, as well as receiving credits associated with selfprovision of ancillary services remain uncertain under the No Action Alternative. Without a vehicle to bill or to be paid for services, the economics of Western's operations associated with this alternative are unknown. Because of the uncertainty associated with the cost structure that Western would experience under the No Action Alternative, this alternative does not meet the cost effectiveness criteria.

Summary Analysis of the No Action Alternative

The No Action Alternative outlined during this public process is unlike other no action alternatives usually associated with a proposed project or policy. In a normal no action alternative, the status quo is preserved and proposed project/policy alternatives are compared with the status quo. In this case, the status quo does not represent the no action alternative as existing contracts with PG&E terminate while Western is simultaneously implementing a new marketing plan. PG&E has explicitly stated that it is not interested in extending or renewing these contracts. With the status quo not available as an option, Western must move toward establishing a new business identity and/or business operating arrangement that will allow it to continue doing its daytoday business. Taking no action prior to January 1, 2005, will require Western to put in place some type of arrangement to operate within the ISO control area as soon as possible after January 1, 2005.

The No Action Alternative will place Western in a highly undesirable business posture. Without longterm business arrangements in place, Federal power resources cannot be delivered reliably and costeffectively to Project Use, First Preference Power, and Preference Power delivery points located on the ISOcontrolled grid and not directly connected to the Federal transmission system. Lack of any permanent business arrangements would not allow Western to participate in the ISO markets and allow excess generation and ancillary services to be sold and the revenues used to accelerate repayment on the Federal investment. The No Action Alternative impacts Western's ability to meet its statutory obligations to provide energy to Project Use loads on the ISOcontrolled grid and meet its contractual obligations to deliver Federal power to First Preference and Preference Power customers who use the ISOcontrolled grid. Western has determined that it is not prudent to implement the No Action Alternative.

Western's analysis of the five evaluation factors is summarized in the table below:
No Action Alternative Evaluation Summary
Almost Does not Evaluation factors Meets meets meet Flexibility............................... ........ ........ XX Certainty................................. ........ ........ XX Durability................................ ........ ........ XX Operating Transparency.................... ........ ........ XX CostEffectiveness........................ ........ ........ XX The Participating Transmission Owner Alternative

Western would execute a Transmission Control Agreement (TCA) with the ISO under the PTO Alternative. Executing a TCA would transfer operational control over Western's transmission system to the ISO. Reclamation would execute a PGA with the ISO. Executing a PGA would allow the ISO to control Reclamation's generation and allow Western to fully participate in the ISO markets by receiving revenues associated with any excess generation.

The CVP was authorized primarily as an irrigation project. Therefore, Project Use energy requirements have first priority for the hydropower generated from the facilities. Hydropower generation in excess of Project Use energy requirements is available to be sold to CVP Preference Power customers. This legislative requirement would need to be appropriately accommodated in any future agreement executed between Reclamation, Western, and the ISO. The specific terms and conditions relating to ISO operational jurisdiction over Federally owned generation and transmission facilities would also need to be carefully evaluated to assure that as a result of implementing this alternative, the authorized project purposes of the CVP are not impaired.

If the appropriate arrangements were worked out with the ISO, at a minimum, Western would need to retain responsibility and operational control over switching operations and the maintenance and replacement of its transmission facilities. Similarly, Reclamation would also, at a minimum, need to retain responsibility and operational control over its hydropower facilities/operations and the maintenance and replacement of its generating facilities. Under existing authorizations, the responsibility and operational control over the water and power operations of the CVP cannot be impaired.

The ISO would become responsible for scheduling the use of the CVP transmission system and Western's
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MalinRound Mountain transmission line. Western currently is the operating agent for COTP. Depending on the arrangements that would ultimately be made for this line, the ISO may also assume operational control of this transmission line. Under its current COTP agreements with TANC, Western would retain responsibility for furnishing technical services associated with the longterm maintenance and replacement of these facilities. The ISO would assume scheduling responsibility for the entire threeline COI system south of the Oregon border and would continue in its role as the single path operator.

Operating Scenario To Evaluate the PTO Alternative

Under the PTO Alternative, Western would not have a physically discrete and defined transmission system. From an operational perspective, Western's transmission system would be integrated with the ISO control area. Western would schedule energy deliveries for Project Use loads, First Preference customers, and other Preference Power customers with the ISO under generation schedules developed by Reclamation and Western. Western would act as the Scheduling Coordinator (SC) for these deliveries and pass through ISO charges associated with generation, including imbalance energy charges, reserve charges, and other charges required to meet the ISO's costs of operating the control area. Western's customers, including those that are directly connected to the Federal transmission system and those served through PG&E facilities, would be billed all of the appropriate ISO charges associated with those energy deliveries. Western would identify its transmission revenue requirements which would be collected by the ISO.

From an operational perspective, Western would need a 24hour Merchant Desk to purchase energy required to support Project Use energy requirements, as well as to meet the supplemental energy needs of Western's Variable and Full Load Service customers under its post2004 Marketing Plan. Western would provide SC services for Variable or Full Load Service customers requesting this service, as well as for Reclamation's generation facilities. Under its current operating procedures, the ISO requires each SC to maintain a 24hour Merchant Desk in order to maintain SC certification status.

Western would also have to maintain a 24hour Switching Desk to perform switching for outages of system elements (such as transmission lines and breakers) for maintenance, repair, or replacement, or to assist the ISO in restoring the system following a disturbance. Since the ISO would schedule the use of Western's transmission system, Western would not have to maintain a 24hour Transmission Scheduling Desk. Western would also not have to maintain a 24hour Automatic Generation Control (AGC) Desk because Reclamation's generation would be dispatched by the ISO under a PGA. As a third party to this transaction, Western could face increased risk and uncertainty as it implements its new marketing plan since it would not necessarily have direct realtime knowledge about the operation and generation status of Reclamation's hydropower facilities.

From an organizational perspective, Western would still need to retain its power accounting, billing, and settlements functions to monitor and credit/bill for products and services purchased and sold under to its marketing plan, as well as to reconcile ISO billings. Staff would be required to verify the accuracy and integrity of the accounting records and issue invoices to Western's customers and the ISO as appropriate. The ISO now has more than 100 separate charge types. Depending on the nature and complexity of the future financial settlements, this function may require additional staffing above current levels.
Evaluation of the Flexibility Criteria Under the PTO Alternative

Implementing the PTO Alternative would subject Reclamation and Western to the terms of the ISO Tariff for the term of the PGA and the TCA, respectively. Western and Reclamation would conform their business practices to those required under the ISO Tariff. If a new RTO is established and the ISO chooses to join, any changes that the ISO would need to make to its existing operating and business protocols would also have to be made by Reclamation and Western. Western and Reclamation would have to either comply with any changes required within the time frames established by the ISO or choose to terminate the TCA and PGA, respectively. Because of the present 2year notice requirement, the effective date of the termination is not immediate. In the interim, as a PTO, Western and Reclamation would need to conform their business practices to the extent not precluded by Federal law.

If the ISO is certified by the Commission as an RTO, any changes that the ISO would need to make as a result of its new role would presumably be incorporated in its tariff. Reclamation and Western could choose to either undertake the necessary changes in their respective business processes or choose to terminate the PGA and TCA, respectively. Because of the notice requirement, the effective date of the termination would not be immediate. In the interim, as a PTO, Western and Reclamation would need to conform their business practices to the extent not precluded by Federal law.

The electric utility industry is in a state of ongoing change. New policies, procedures, and practices are being adopted to reform and restructure the energy markets. NERC and WECC are coordinating industry wide changes to existing operating standards and protocols to ensure the continued reliable operation of the electric power grid. As industry wide consensus is achieved, under the PTO Alternative, the ISO would presumably modify its tariff as needed.

The flexibility to join whatever RTO that Western chooses is of concern to some of the commentors. For instance, the TID commented ``A [Federal Control Area] FCA allows for choice concerning which Regional Transmission Organization (RTO) Western [Sierra Nevada Region] SNR joins. Other alternatives require that Western joins the RTO that the CAISO desires.''

The TID continued:

TID believes that the customers of Western should be able to choose what business environment they prefer to operate within. Customer choice was the linchpin in many arguments advocating competitive markets and California's electric industry
restructuring. A Western FCA will give customers a choice between operating under the volatile CAISO market structure and a cost based, relatively predictable model. Under a Western FCA, customers will have the choice of participating and being a part of the CAISO if they choose. If Western chooses any of the options that make it subordinate to the CAISO or the CAISO Tariff, Western will have made the choice for many Western customers.

Under Contract 2948A, transmission and ancillary services are provided by the ISO to PG&E on behalf of Western. Western's offsystem customers receive transmission service from the ISO and through Western under Contract 2948A. Directconnected customers receive transmission service and ancillary services from Western and the ISO through PG&E, respectively, under Contract 2948A. When Contract 2948A terminates on January 1, 2005, under this alternative, these services would be provided by the ISO to all of Western's customers unless the customer can selfprovide some of these services. In essence, all of Western's customers will be, by default, subject to the charges
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associated with the ISO Tariff. The TID appears to equate the lack of choice with a lack of flexibility to choose when they enter or leave the ISO environment.

Western believes that choosing the PTO Alternative would give it the shortterm flexibility needed to adapt to NERC and WECC policy changes. The longterm flexibility of joining whatever RTO Western chooses is minimally constrained by the current 2year TCA termination notice. Western, therefore, concludes that the PTO option meets the flexibility criteria.
Evaluation of the Certainty Criteria Under the PTO Alternative

Under the PTO Alternative, Western would be subject to all of the ISO charges associated with being the SC for Reclamation to schedule Base Resource and Custom Product to its customers. The SC for each customer would be subject to all of the ISO charges associated with scheduling and delivering power to the customer's delivery point and the associated ancillary services. Many of the ISO charges, such as imbalance energy and reserves, fluctuate on a daily basis with spot market price variations. Although a portion of this risk may be minimized through forward purchases, this alternative does not provide Western with the ability to load follow. Unanticipated energy imbalance charges may still arise as a result of normal project operations. Transmission and deliveryrelated charges as well as overhead charges of the ISO may change less frequently, but based on historical trends, these costs are expected to change more frequently than Western's.

The ISO is in the midst of implementing new operating guidance for its Market Redesign (MD02). The proposed new initiative would implement the concept of locational marginal pricing to deal with transmission congestion. If MD02 is implemented in its current format, during periods of congestion, the ISO would redispatch all generation based on economic factors. Under this alternative, during periods of congestion, affected CVP Preference Power customers and Project Use loads could end up paying a different price than the actual costofservice rates associated with Federal hydropower resources. These rates may not be consistent with Reclamation law and policy, and Western may need to consider mitigation strategies.

Several of Western's customers are concerned with the predictability and stability of any alternative selected by Western. The TID summarized its view of certainty by stating that under the PTO option, the cost of power from generation to load will be set by a market that cannot be forecast with any certainty. The TID also commented that the Western rate process is open and generally results in a fair allocation of costs based on cost causation principles. The TID contrasts the Western process with the ISO stakeholder process as follows:

This can be contrasted to the CAISO method of allocating costs, which does not accept meaningful direction from stakeholders representing consumers. Rather, the CAISO seems willing only to socialize costs in order to make it seem that the costs of CAISO services are less prohibitive.

The TID also states that transmission allocation based on firm physical transmission rights adds certainty to longterm and shortterm planning. TANC commented:

Firm physical transmission rights are a prerequisite to a stable forward energy market. With known physical rights there is no need for unpredictable congestion management schemes, multiple markets, and there is no fictitious congestion. Without firm physical transmission rights it is commercially imprudent to contract in the forward markets. The CAISO provides transmission for a maximum period of one day, and those who are willing to pay the most get to use the transmission grid.

The City of Palo Alto stated:

The City values longterm transmission contracts for establishing firm transmission rights and obligations of load serving entities. Western has always utilized this approach to deliver Western energy to its customers. This provides cost and operational certainty that the CAISO Tariff, and market cost based approach to service, does not provide.

The TPUD commented:

The Cal ISO prepares rate amendments on an average of one every three to four weeks. By contrast, Western ratemaking occurs an average of once every three to four years. The Cal ISO has some 250 different rates. Even with a Federal control area it is doubtful that Western will have a tenth as many.

The ArvinEdison Water Storage District stated:

Despite the best of intentions and a talented staff, the California Independent System Operator (CAISO) is mired in unwieldy governance that results in perpetual tariff revisions and market redesigns. Each revision results in added costs and complexity that bog the CAISO with some of the highest overhead expenses, and hence the highest grid management costs of any current ISO or RTO in the nation.

Reclamation stated:

Costs of CVP operation have not changed significantly except due to escalation or increased maintenance as the facilities have aged. This situation would change significantly should the CVP become a part of the CAISO. As the largest CVP load, Reclamation does not want the CVP beneficiaries to be exposed to CAISO operational costs beyond what the historical CVP cost of operations have been.

The ISO commented:

The ISO's transmission rates are based on Commission approved costofservice basis and on an open and nondiscriminatory basis to all market participants * * * the only volatility Western would experience is through buying and selling in the ISO's Ancillary Services and RealTime Imbalance Energy markets. However, this volatility is present regardless of whether or not Western becomes a control area, and the degree of volatility is based on Western's need to procure additional resources. If Western has sufficient resources, the volatility of these markets would not impact Western and its customers.

Under the PTO Alternative, although Western may retain its ability to purchase power in the forward markets to reduce energy imbalance charges during realtime operations, since Western would not be able to load follow, it would not have the ability to respond to significant changes during realtime operations. Consequently, to the extent that Western is short resources, Western would be subject to any volatility in the ISO's ancillary services and realtime energy imbalance markets.

Western must set its rates at the lowest possible level consistent with sound business practices, but must cover all of its costs, including amounts to repay the project investment over the prescribed repayment period. In the past, Western's costs have been stable with rate adjustments made on an average of once every 3 years. Western's rates are set in an open public process designed to assure that customer concerns are accommodated through an appropriate rate design and cost allocation methodology.

The rate certainty associated with each of the operational alternatives is important in the post2004 time period. Rate changes could occur more frequently if Western chose an operational alternative where it is subject to more frequent changes in cost. Under the PTO option, Western would be subject to changes in ISO costs that are not within Western's ability to control. For example, between 19992002, the ISO revenue requirement for grid management charges increased from $158.7 million to an estimated $239.2 million, an increase of more than 50 percent. Western's customers have expressed an intense interest in assuring that the post2004 operational alternative selected is responsive to cost containment principles so that to the
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maximum extent practicable, the rates for products and services are stable and business certainty is maintained.

The commentors quoted previously also equated certainty with having physical longterm transmission rights. These physical rights are unavailable from the ISO under the PTO Alternative. As pointed out by TANC, transmission service is only available on a daytoday basis and is allocated to those willing to pay the highest price. There is no business certainty associated with a forward purchase that requires transmission to get power to load if, daytoday, the price of transmission varies significantly. A forward purchase of energy believed to be economical under one set of assumed transmission costs can rapidly become uneconomical if the cost of transmission increases significantly over a short period of time. Under the PTO Alternative, customers would be subject to these variable changes in transmission service costs because the use of Western's transmission system would be governed by the ISO and would be subject to all of the ISO charges. To the extent existing right holders may be eligible to receive congestion revenues, they may be able to mitigate some of this price uncertainty but not to the same extent provided by physical transmission rights.

Under the PTO Alternative, Western would also be responsible for paying ISO overhead charge increases as the SC for Base Resource and Custom Product schedules. If Western does not incur significant energy imbalance or ancillary service charges from the ISO, Western's costs may not escalate as rapidly and be as variable as the ISO's in the recent past. However, Western's customers could experience additional costs associated with the transmission and delivery of their energy due to marketbased charges for congestion and ancillary services. Although prices are relatively stable now, Western and its customers may still be subject to uncontrollable marketbased risk, as well as the uncertainties associated with the implementation of MD02. Western concludes that this alternative does not meet the certainty criteria. Evaluation of the Durability Criteria Under the PTO Alternative

In general, operating and business protocols and practices are established and defined by the agreements which create the relationship. These agreements establish obligations and
responsibilities of the parties and allocate the burdens and benefits of each business relationship. Under the PTO option, the basis for Western's relationship with the ISO is the ISO Tariff. Because the ISO is a tariffbased organization, after a PTO executes a TCA, the operating terms, conditions, rates, and other pertinent aspects governing a PTO's business arrangements with the ISO can change with the filing of new ISO Tariff amendments. In the event Western and the ISO cannot agree upon potential changes to its existing agreement(s), the ISO can submit its proposed changes to the Commission for resolution.

Many commentors expressed reservations about the durability of any arrangement with the ISO because it uses a tariffbased approach. Many of the comments equated stable, longterm business relationships occurring through contract and not tariffbased relationships.

For instance, the TANC stated:

We believe in the durability of longterm contracts for establishing rights and obligations of load serving entities. Western has always utilized this approach to doing business. The CAISO has historically attempted to alter the rights and obligations of existing contracts. The CAISO utilizes tariffs that can and have been frequently changed. The CAISO files amendments too frequently to consider the CAISO Tariff durable or predictable.

Others including the MID, the TID, and the SVP cite the 55 amendments that the ISO filed at the Commission in the last 5 years as evidence that a relationship with the ISO is not durable.

The ISO commented:

The ISO's operating protocols have remained substantially the same since the ISO startup date in 1998. The only changes in operating protocols are based on the need to comply with changing operational criteria from the NERC and WECC. However, every control area, including the Western Control Area, would have to make similar changes over time. Admittedly, the ISO has necessarily changed the protocols associated with markets, market implementation, and market rules a number of times over the past 6 years. Given that the ISO was the first of its kind in the United States, an evolutionary process has been necessary when it comes to markets. Thus Western's concern with durability with respect to operating protocols has been met, but market durability is still evolving and will continue to evolve for a number of years to come. Western cannot disguise its concern regarding ``operating protocol durability'' as an offhand reference to the energy crisis and changing market rules. Moreover, the ISO's ongoing market modifications are designed to promote stability based on experience, best practices, and coordination of operations to the benefit of all California consumers and market participants.

Fiftyseven ISO Tariff amendments have been filed since the ISO became operational in 1998. Western notes that the ISO has filed four tariff amendments since this public process began on June 24, 2003. Although it is important to distinguish between procedural and substantive changes to the ISO Tariff, the underlying ability of the ISO to undertake changes to its business and operating protocols and procedures creates business uncertainty and risk.

Based on the affected term or condition, these change