[Federal Register Volume 68, Number 231 (Tuesday, December 2, 2003)]
[Notices]
[Pages 67417-67437]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 03-29984]


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DEPARTMENT OF ENERGY

Western Area Power Administration


Operational Alternative for Post-2004 Operations

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of proposed decision.

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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 
post-2004 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 contract-based sub-control 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.

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 e-mail 
to deliver comments.

ADDRESSES: Written comments should be sent to Tom Carter, Power 
Operations Manager, Sierra Nevada Region, Western Area Power 
Administration, 114 Parkshore Drive, Folsom, CA 95630-4710, or by e-
mail to [email protected].

SUPPLEMENTARY INFORMATION:

Authorities

    The selection of an alternative for post-2004 operations is made 
under the authorities contained in the Department of Energy 
Organization Act (42 U.S.C. 7101-7352); 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

[[Page 67418]]

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/pifq-as1.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 decision-making 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 twenty-six 
(26) different entities. Western posted the comment letters at http://www.wapa.gov/sn/initiatives/post2004/opScenarios/Comments08-08-03/ 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 investor-owned 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 decision-making factors 
proposed by Western, and raised issues and concerns about implementing 
an operational alternative.

Decision-Making 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 cost-effectiveness.
    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 cost-of-service 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 long-term 
business planning and to undertake prudent long-term 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.
    Cost-effectiveness 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 post-2004 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 cost-effective. 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 decision-making 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 decision-making 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 long-term 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

[[Page 67419]]

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 post-2004 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 post-2004 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 decision-making 
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 Post-2004 Power Marketing Plan

    For Western to implement its post-2004 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 post-2004 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 14-06-200-2948A (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 post-2004 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 self-provided 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 post-2004 Marketing Plan is that Western and its customers will be 
exposed directly to real-time changes in the market. Previously, under 
Contract 2948A, Western and its customers settled with PG&E on a 
monthly after-the-fact 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 post-2004 
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 day-ahead 
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 day-ahead schedules and any real-time 
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

[[Page 67420]]

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 day-to-day 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 day-to-day operations. The information stored in the 
data repository will be used by the maintenance, operations, and power 
billing functions to conduct day-to-day 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 cost-of-service 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 post-2004 
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 post-2004 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 2002-2004.

Comparative Economic Benefits Study

    Navigant prepared a comparative economic analysis of each post-2004 
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 cost-effective 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 least-cost 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 cost-effective of the three 
alternatives being considered.
    The revised comparative benefits study incorporated the following 
recommended changes to the assumptions: (1) Changing the treatment for 
self-provided 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 94-mile 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 direct-connected 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 post-2004 operating 
alternative over a 15-year 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 Post-2004 Alternative
                                                                [In millions of dollars]
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                                                             Participating      Metered         Federal
                                                             transmission      subsystem     control area    FCA option B    FCA option C   FCA option D
                                                             owner option       option         option A
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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 post-2004 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 direct-connected Reclamation Project Use loads. 
Scenario B assumed formation of a control area which included Scenario 
A and three direct-connected Preference customers (Cities of Redding, 
Roseville, and Shasta Lake). Scenario C assumed all elements from 
Scenario B and added the following three other direct-connected 
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 post-2004 operational alternatives, an estimate 
of annual operating expenses associated with each alternative was 
developed. The table below summarizes Western's estimated cost for each 
post-2004 operational alternative.

                    Post-2004 Operational Alternatives Cost Summary Estimated Annual Expenses
                                            [In millions of dollars]
----------------------------------------------------------------------------------------------------------------
                                                                   Participating      Metered         Federal
                                                                   transmission      subsystem     control area
                                                                   owner option       option       options (A-D)
----------------------------------------------------------------------------------------------------------------
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 One-Time 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 post-2004 Power Marketing Plan,'' much of the Information 
Technology infrastructure is required to implement the post-2004 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 24-hour 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 contract-based 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 post-2004 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 14-06-200-
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 investor-owned 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.

[[Page 67422]]

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 long-term 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 California-Oregon 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 off-system 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 post-2004 
successor operational alternative, it would continue to reside within 
the ISO control area. Under the No Action Alternative, Western would 
not have long-term 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 short-term (non-firm) 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 long-term business arrangements, the ISO would not be 
obligated to provide services to Western. The converse is also true for 
Western. In the absence of long-term 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 direct-connected 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 off-system 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 day-to-day business operations. Without long-term 
business arrangements, Western would have to rely on short-term 
arrangements with the ISO and others after January 1, 2005, to continue 
to do its business. Although these short-term arrangements do not 
commit Western to a long-term 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 long-term business 
arrangements, Western would have no basis for requiring the ISO or PG&E 
to deliver power to Western's off-system Project Use loads or 
Preference Power customers served using the ISO-controlled grid. On 
January 1, 2005, Western would not have negotiated long-term mutually 
beneficial business arrangements with the ISO or PG&E and, 
consequently, would have to undertake short-term 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 long-term rate certainty and, in 
the event rates increase faster than Western's ability to undertake 
changes through its formal rate-setting process, Western would face the 
potential of significantly reducing its power deliveries to avoid any 
potential violations of the Federal Anti-Deficiency Act. The underlying 
uncertainty would also inhibit long-term 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 short-term 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 long-term business arrangement with the ISO for operation 
of Western's transmission system within the ISO control area. Since 
Western would not have a long-term business arrangement with the ISO, 
every transaction would be accomplished on an interim, short-term 
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 ISO-controlled grid since

[[Page 67423]]

it could buy transmission on only a non-firm 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 three-line COI, and potential new business 
arrangements on the California-Oregon 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 Cost-Effectiveness 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 day-to-day 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 
long-term 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 self-provision 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 
day-to-day 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 long-term business arrangements 
in place, Federal power resources cannot be delivered reliably and 
cost-effectively to Project Use, First Preference Power, and Preference 
Power delivery points located on the ISO-controlled 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 
ISO-controlled grid and meet its contractual obligations to deliver 
Federal power to First Preference and Preference Power customers who 
use the ISO-controlled 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
Cost-Effectiveness........................  ........  ........       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

[[Page 67424]]

Malin-Round 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 long-term maintenance and replacement of 
these facilities. The ISO would assume scheduling responsibility for 
the entire three-line 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 24-hour 
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 post-2004 
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 24-hour Merchant 
Desk in order to maintain SC certification status.
    Western would also have to maintain a 24-hour 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 24-hour Transmission Scheduling 
Desk. Western would also not have to maintain a 24-hour 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 real-time 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 2-year 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 off-system 
customers receive transmission service from the ISO and through Western 
under Contract 2948A. Direct-connected 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 self-provide some of these services. In essence, all of Western's 
customers will be, by default, subject to the charges

[[Page 67425]]

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 short-term flexibility needed to adapt to NERC and WECC policy 
changes. The long-term flexibility of joining whatever RTO Western 
chooses is minimally constrained by the current 2-year 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 delivery-related 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 cost-of-service 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 long-term and short-term 
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 long-term 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 Arvin-Edison 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 
cost-of-service basis and on an open and non-discriminatory basis to 
all market participants * * * the only volatility Western would 
experience is through buying and selling in the ISO's Ancillary 
Services and Real-Time 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 real-time operations, since Western would not be able to 
load follow, it would not have the ability to respond to significant 
changes during real-time operations. Consequently, to the extent that 
Western is short resources, Western would be subject to any volatility 
in the ISO's ancillary services and real-time 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 post-2004 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 1999-2002, 
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 post-2004 operational alternative selected is 
responsive to cost containment principles so that to the

[[Page 67426]]

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 long-term 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 day-to-day 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, day-to-day, 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 market-based charges for congestion and ancillary services. Although 
prices are relatively stable now, Western and its customers may still 
be subject to uncontrollable market-based 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 tariff-based 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 tariff-based approach. Many 
of the comments equated stable, long-term business relationships 
occurring through contract- and not tariff-based relationships.
    For instance, the TANC stated:

    We believe in the durability of long-term 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 start-up 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 off-hand 
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.

    Fifty-seven 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 changes could 
materially affect the relationship between the benefits and burdens 
that each party would receive and impart from being a PTO. Stakeholders 
continue to have ongoing concerns related to the frequency and number 
of ISO Tariff amendments. Although many of these changes would parallel 
changes that other control area operators must implement in response to 
ongoing industry changes, because of their frequency and the number of 
substantive changes made, Western concludes that the PTO Alternative 
almost meets the durability criteria.
Evaluation of the Operating Transparency Criteria Under the PTO 
Alternative
    As a PTO, Western's transmission system would be scheduled and 
dispatched by the ISO as a part of the ISO-controlled grid. Assuming 
that the operational jurisdictional issues identified earlier in the 
description of the PTO Alternative are satisfactorily resolved, Western 
and Reclamation would operate its system under the operating protocols 
and procedures established by the ISO. Because the ISO is a NERC- and 
WECC-certified control area, the ISO would, in the ordinary course of 
its business, coordinate changes to its system operations with 
bordering control areas or provide appropriate mitigation measures to 
minimize the impacts of such changes to neighboring control areas. With 
respect to impacts to third parties, the PTO Alternative meets the 
requirements of the operating transparency criteria.
Cost-Effectiveness Criteria Under the PTO Alternative
    Navigant prepared a comparative economic analysis of each post-2004 
operational alternative under consideration on behalf of Reclamation 
and Western. Navigant's 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 that the PTO option was the 
least cost-effective.
    During the public comment period, the ISO and other commentors

[[Page 67427]]

questioned some of the underlying assumptions used in the Navigant 
study. The ISO submitted a separate economic analysis showing that both 
the PTO and MSS options were the least cost options. Navigant reviewed 
the assumptions used in its initial comparative economic benefits 
study. A number of the suggested changes were accepted and incorporated 
into a revised comparative economic benefits study. The revised study 
continues to indicate that from an overall comparative economic 
standpoint, the PTO option continues to remain the least cost-effective 
of the three alternatives.
    During the public process, some views expressed on the comparative 
economic benefit studies performed by Navigant and the importance of 
the cost-effectiveness criteria included:
    The TANC commented:

    * * * given the rapid escalation of the CAISO costs, numerous 
inaccuracies of CAISO settlements, and extreme complexity and 
variability of CAISO market design, assumption-based cost forecasts 
in the CAISO environment are difficult to estimate and cannot be the 
most important evaluation criteria for Western and its Customers.

    The TPUD stated:

    The Navigant study and the forthcoming Cal ISO study, which will 
no doubt repudiate most, if not all, of Navigant's work, are a waste 
of time, money and effort. A prediction of how many tariff 
amendments the Cal ISO will file over the next twenty years would be 
more certain than anyone's prediction of the Cal ISO costs just two 
years from now.

    The TID commented:

    Western should not be persuaded to forego the FCA [Federal 
Control Area] option because some indicate that it may not be the 
low cost option. If, as the CAISO, and perhaps others, purport, 
participating in the CAISO is the most cost effective approach, then 
over time, Western customers will migrate to the CAISO market. The 
CAISO has a mission of being the preferred transmission provider. If 
they meet the goal, Western customers will find ways to participate 
and join the CAISO.

    The ISO and a number of other commentors were concerned that 
Western has the information it needs to make a fully informed decision, 
and that the decision recognize and incorporate the needs of all the 
parties, and not just a small subset of users. Although Western is 
aware of the issue of impacts to statewide ratepayers, under 
Reclamation law, Western's legal obligations are to Project Use and 
Preference Power customers. Western views the Navigant study as a 
screening study to determine the comparative differences between the 
alternatives and to determine which alternatives, if any, were 
significantly more or less cost-effective than the others. The study 
looked at the cost of delivering power to Federal Base Resource and 
Custom Product customers to the customers' delivery point(s). Western 
believes that the study used reasonable assumptions and cost data based 
on information available at the time. Western analyzed the comments and 
determined that since the PTO Alternative is the most expensive from 
the comparative economic benefits perspective, the PTO Alternative 
almost meets the cost-effectiveness criteria.
    Under the terms and conditions of Contract 2948A, PG&E agreed to 
provide transmission service to Federal Project Use and Preference 
Power customers instead of the Federal Government constructing its own 
transmission system. Although this contract contains an expiration 
date, since PG&E's actions precluded the Federal Government from 
constructing its own facilities, Western asserts that PG&E is 
responsible for assuring the delivery of Federal power at rates 
consistent with its embedded cost of service. Therefore, any cost 
increases for transmission service beyond those already established 
under the terms and conditions of Contract 2948A constitute a cost 
shift to Reclamation's Project Use loads and Western's Preference Power 
customers. Since PG&E is presently paying these costs, costs to 
statewide ratepayers would not increase if the current arrangements 
continue.
Summary Analysis of the PTO Alternative
    The PTO Alternative integrates the Federal generation and 
transmission system with the ISO-controlled grid. Under this 
alternative, Western's customers would be subject to all of the ISO 
charges associated with transmission and delivery of Federal power at 
their delivery points. For off-system Project Use loads and Preference 
customers, the resulting increase in ISO transmission and related 
charges would result in a cost shift from the transmission service now 
provided by PG&E under Contract 2948A. These customers are currently 
provided transmission service by PG&E for Federal power at embedded 
cost rates. Western's off-system Project Use and Preference customers 
would be subject to all of the ISO charges associated with transmission 
and delivery of Federal power to them. These charges represent a 
significant increase in costs to off-system Project Use loads and 
Western's Preference customers. These costs are now being paid to the 
ISO by PG&E under terms of Contract 2948A but will be charged to off-
system Project Use loads and Preference customers after January 1, 
2005. Unless successor arrangements can be successfully negotiated with 
PG&E, and/or other cost allocation arrangements undertaken, these cost 
shifts are unavoidable not only under the PTO, but also for the MSS, 
sub-control area, and control area alternatives. Western will consider 
alternatives to minimize these cost shifts to its customers as part of 
its formal rate process.
    For Project Use loads and Preference customers directly connected 
to the Federal transmission system, the cost-of-service rates would 
increase substantially, as transmission access charges would increase 
from cost-of-service rates associated with Federal transmission 
facilities to include the cost of statewide transmission. This would 
result in a significant cost shift to these users without a 
corresponding increase in service or benefits.
    As the SC for Reclamation's generation and for customers who have 
contracted for this service, Western's overall cost to deliver Federal 
power to the ISO grid may not significantly increase if it is able to 
operate to minimize the need to purchase significant amounts of 
imbalance energy and/or ancillary services under the PTO Alternative. 
From an infrastructure standpoint, the PTO Alternative will still 
require development and implementation of all of the systems described 
previously in the section entitled, ``Implementing the Post-2004 Power 
Marketing Plan,'' except for the reliability support function portion 
of the Scheduling system. Implementing the PTO Alternative would 
eliminate the need for a scheduling system to support the reliability 
function. However, additional programming would be required to assure 
that data would be appropriately collected and shared between Western's 
Power Marketing and Power Operations functions and the ISO.
    From a staffing standpoint, Western would have to maintain a 24-
hour Merchant Desk and a 24-hour Transmission Switching Desk, requiring 
an estimated 15 positions. The Transmission Switching Desk already 
exists. Western intends to hire the Merchant Desk positions from within 
the organization to the maximum extent possible to minimize the need 
for new staff and to continue transforming its organization to meet the 
needs of its new Marketing Plan. In addition, Western may need to add 
staff to the Settlements function to reconcile ISO charges and issue 
bills to customers for SC services provided to some of the customers as 
charged by the ISO to

[[Page 67428]]

Western. Under the PTO alternative, the intent is to use existing staff 
to the maximum extent possible.
    This table summarizes the relative ratings of each evaluation 
criteria for the PTO Alternative:

                   PTO Alternative Evaluation Summary
------------------------------------------------------------------------
                                                       Almost   Does not
            Evaluation  factors               Meets     meets     meet
------------------------------------------------------------------------
Flexibility...............................       XX   ........  ........
Certainty.................................  ........  ........       XX
Durability................................  ........       XX   ........
Operating Transparency....................       XX   ........  ........
Cost-Effectiveness........................  ........       XX   ........
------------------------------------------------------------------------

The Metered Subsystem Alternative

    The ISO defines an MSS as the system of a transmission owner 
bounded by ISO-certified revenue quality meters at each interface point 
and generating units internal to that metered system. Upon execution of 
an MSS agreement or an MSS aggregator agreement with the ISO, the 
agreement would establish Western's transmission system boundaries and 
identify which direct and non-direct connected entities would be 
included within Western's MSS. Western would remain responsible for 
operating, maintaining, and replacing the CVP transmission facilities. 
Reclamation would not be required to execute a PGA with the ISO. 
Reclamation would remain responsible for switching, maintaining, and 
replacing the CVP's generating facilities.
    Under this alternative, Western could operate as a sub-control area 
within the ISO control area and would be responsible for scheduling the 
use of the CVP transmission system and Western's Malin-Round Mountain 
transmission line. Assuming that Western remained as the COTP operating 
agent, this line would also be under the operational control of 
Western, with Western continuing to be responsible for maintenance and 
replacement of these facilities. Western would have the scheduling 
responsibility for use of the CVP transmission system, the COTP, and 
the Malin-Round Mountain transmission line. The ISO would remain as the 
single path operator for the entire COI.
Operating Scenario To Evaluate the MSS Alternative
    Under the MSS Alternative, Western would have a physically defined 
contiguous system that includes those customers wishing to participate. 
Although the ISO allows off-system loads to be aggregated together and 
incorporated into an aggregated MSS, because of possible resource 
constraints associated with following the loads of individual 
participants, Western would need to retain operational flexibility over 
the ultimate size of the MSS and the timing of when new participants 
would be added. Initially, Western would limit the size of the MSS to 
First Preference, Project Use loads, and direct-connected Preference 
Power customers wishing to participate. Other Preference Power 
customers may be added, as Western gains operational experience. The 
aggregated MSS would be similar in concept to dynamic scheduling from 
one control area to another. Western's system would be integrated 
within the ISO control area, but Western would manage the net power 
flows through the interconnection points with the ISO. Western would be 
responsible for scheduling energy deliveries to Project Use load, First 
Preference customers, and other Preference customers within the MSS. 
For customers not participating in the MSS, Western would schedule 
deliveries with the ISO under generation schedules developed by 
Reclamation and Western.
    Western could self-provide imbalance energy and ancillary services 
to the MSS and could participate fully within the ISO markets if excess 
generation or reserves were available. Under the MSS Alternative, 
Western would operate the contiguous Federal system as a sub-control 
area within the ISO control area. Off-system customers that are 
participants in Western's MSS would be included, from an accounting 
standpoint, as if they were inside that sub-control area, in a similar 
fashion to Western dynamically scheduling to off-system participants. 
Under the MSS Alternative, the aggregated MSS net scheduled interchange 
with the ISO would be followed on a 10-minute basis (or possibly 5-
minute basis) by Western. The imbalance energy provided by the ISO 
would be determined as the deviation from net scheduled interchange of 
the aggregated MSS participants, integrated over a 10-minute period (or 
5-minute period). This is different from dynamic scheduling in that 
Western would follow deviations from net scheduled interchange on a 4-
second basis.
    Western would pay all the ISO charges associated with the 
aggregated net flows into the MSS. Off-system Project Use loads and 
Preference customers participating in the MSS would also be charged for 
use of the ISO grid. Western's customers directly connected to Western 
would not be subject to charges for use of the ISO grid to deliver 
Federal power. However, off-system Project Use loads and Preference 
customers would incur all of the ISO transmission and related charges 
associated with the net energy deliveries to the MSS. Western would 
market transmission service to its customers in a similar fashion as is 
done today.
    From an operational perspective, Western would have a 24-hour 
Merchant Desk to purchase energy required for Western's Variable 
Resource and Full Load Service customers and would be the SC for those 
customers. The 24-hour staffing of the Merchant Desk is required by the 
ISO for Western to maintain SC status. Western would also have to 
maintain a 24-hour 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 Western would be scheduling 
the use of its transmission system and those elements of the COI it 
owns or is responsible for under contract, Western would maintain a 24-
hour Transmission Scheduling Desk. Western would also maintain a 24-
hour AGC Desk to self-provide ancillary services and to minimize 
imbalance energy purchases.
    From an organizational perspective, Western would continue to need 
a power accounting, billing, and settlements function to account for 
services purchased and sold, reconcile billings from the ISO and others 
to the accounting records, and issue invoices to Western's customers 
and the ISO. Western would also perform the accounting and settlements 
function for the MSS, as aggregated, to reconcile the services 
purchased and delivered to individual MSS members. This could require 
the addition of settlements staff above current levels.
Evaluation of the Flexibility Criteria Under the MSS Alternative
    Implementing the MSS Alternative, like the PTO Alternative, would 
subject Western to the terms and conditions of the ISO Tariff. 
Notwithstanding a contractual agreement, Western would need to conform 
its business practices every time the ISO Tariff is revised. 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 need to be made by Reclamation and Western. Western would 
either comply with any changes required within the time frame required 
by the ISO or choose to terminate the MSS

[[Page 67429]]

agreement. Because of the 6-month notice requirement, the effective 
date of the termination is not immediate. In the interim, as an MSS, 
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. Western could choose to 
either undertake the necessary changes in its business processes or 
choose to terminate the MSS agreement. As with the PTO Alternative, 
because of a specific notice requirement (several existing MSS 
agreements have a 6-month termination notice requirement) the effective 
date of the termination is not immediate. In the interim, as an MSS, 
Western and Reclamation would need to conform their business practices 
to the extent not precluded by Federal law.
    Since Reclamation is not required to sign a PGA under the MSS 
agreement, to the extent that Reclamation chooses not to be party to 
Western's MSS agreement, potential concerns may arise from liability 
that Western could incur from the lack of a contractual relationship 
between the ISO and Reclamation. For example, as the control area 
operator, the ISO could direct that certain generators undertake 
specific actions. To the extent that such actions are inconsistent with 
the project authorization for the CVP, or other Federal law or 
regulation, Western would need to negotiate exceptions to take care of 
Federal legal and jurisdictional issues. The specific terms and 
conditions relating to the ISO's operational jurisdiction over 
Federally-owned generation and transmission facilities would need to be 
carefully evaluated to assure that, as the result of implementing this 
alternative, the authorized project purposes of the CVP would not be 
impaired.
    Because the MSS Alternative specifically requires Western to define 
its physical boundaries, it provides future flexibility to move its 
system intact to another control area or an RTO. While Western is under 
an MSS arrangement, any operating changes necessitated by NERC and WECC 
would presumably be translated into ISO Tariff revisions or operational 
protocol changes.
    Since Western would have its boundaries formed under the MSS 
Alternative, Western believes that this alternative provides for short-
term and long-term flexibility, restricted only by the termination 
provisions of the MSS agreement. However, the MSS Alternative could 
create business uncertainty and unforeseen impacts for off-system 
Western customers should Western decide it would need to terminate its 
MSS agreement. Since the MSS participant continues to retain its 
ability to provide a notice to terminate the MSS agreement at its 
discretion, Western concludes that this option meets the flexibility 
criteria.
Evaluation of the Certainty Criteria Under the MSS Alternative
    The MSS Alternative provides participants the ability to avoid some 
ISO charges because the ISO will base its charges on net flows into the 
MSS, not gross flows as under the PTO option. The ISO indicated charges 
for power deliveries to off-system customers would be based on ``cost 
causation'' principles that would recover the cost for providing the 
product or service. Western interpreted this statement to mean that 
individual customers would be charged for power deliveries based on 
their use of the ISO grid. Some commentors have raised questions 
related to the meaning of ``cost causation.'' For instance, the TPUD 
commented:

    During the July 30 hearing, the Cal ISO's use of the term ``cost 
causation'' was illustrative of their mind set. This term should not 
be confused with ``cost based'' as it seemed the Cal ISO wanted to 
imply. Cost based charges are based on the cost to provide a 
service. ``Cost causation'' is an attempt to appropriately divvy up 
whatever charges a particular provider can get away with under 
whatever the ``Market'' rules are at the time.

    The TID commented on the cost basis for rates under a Federal 
control area and said:

    Under an alternative CAISO approach, the cost of transmission 
from generation to load will be set by a market that cannot be 
forecast with any certainty. Although there may be ways to partially 
hedge the uncertainty, there are costs associated with the hedges 
and hedges are not perfect.

    The ISO is in the midst of implementing new operating guidance for 
its MD02 initiative. The proposed new initiative would implement the 
concept of locational marginal pricing as a means to deal with 
congestion of transmission pathways. If MD02 is implemented in its 
current format during periods of congestion, the ISO would re-dispatch 
all generation based on economic factors. Under this alternative, 
affected CVP Preference Power customers and the Project Use loads could 
end up paying a different price than the actual cost-of-service 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. Unlike the PTO Alternative, where all 
CVP Preference Power customers are potentially impacted, under this 
alternative, those Preference Power customers and Project Use loads, 
which are contained within Western's interconnected generation and 
transmission system (known as the bubble), may be able to mitigate some 
of these impacts.
    Under the MSS Alternative, Western and its customers would avoid 
certain ISO charges. Although Western views the MSS Alternative as 
providing some relief from ISO charges, to the extent that some of 
these charges continue to be market-based and subject to changes from 
tariff amendments, the MSS Alternative continues to present business 
risk and uncertainty. Notwithstanding a contractual agreement, Western 
would need to conform its business practices every time the ISO Tariff 
is revised. Although the MSS Alternative provides some relief from 
costs, to the extent that the charges are subject to potential ISO 
Tariff revisions and the differential MD02 impacts between the direct 
and non-direct connected Preference Power and Project Use loads, 
Western determined that this alternative almost meets the certainty 
criteria.
Evaluation of the Durability Criteria Under the MSS Alternative
    In general, operating 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. In a contractual relationship, these 
practices and procedures are established for the duration of the 
agreement and normally allow the parties to modify parts of the 
agreement over time to properly account for any significant changes in 
the benefits and burdens that may be experienced by either party.
    Under the MSS option, although the relationship between Western and 
the ISO will be based upon an agreement entered into between the 
parties, because the ISO's business operating protocols and procedures 
are tariff based, and not contract-based, the terms, conditions, rates, 
and other pertinent aspects of interacting with the ISO can be changed 
through new ISO Tariff amendments. Notwithstanding a contractual 
agreement, Western would need to conform its business practices every 
time the ISO Tariff is revised. In

[[Page 67430]]

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 of the commentors in this public process expressed concerns 
with the long-term durability of any arrangement with the ISO because 
the agreement would be tariff-based. Many of the comments equated 
stable, long-term business relationships as occurring through contract-
based and not tariff-based relationships.
    For instance, the TANC stated:

    We believe in the durability of long-term 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 such as the MID, the TID, and the SVP cite the 55 amendments 
filed by the ISO 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 start-up 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 off-hand 
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.

    From a durability standpoint, the MSS Alternative is only as 
durable as the ISO Tariff is over time. Fifty-seven ISO Tariff 
amendments have been filed since the ISO became operational in 1998. 
Western notes the ISO has filed four tariff amendments since this 
public process began on June 24, 2003. Notwithstanding a contractual 
agreement, Western would need to conform its business practices every 
time the ISO Tariff is revised. 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 changes can 
materially affect the relationship between the benefits and burdens 
that each party would receive and impart as a result of being an MSS. 
Stakeholders continue to have ongoing concerns related to the frequency 
and number of amendments to the ISO Tariff. Although many of these 
changes would parallel changes that other control area operators must 
implement in response to ongoing industry changes, because of their 
frequency and the number of substantive changes, Western concludes that 
the PTO Alternative almost meets the durability criteria.
Evaluation of the Operating Transparency Criteria Under the MSS 
Alternative
    Under the MSS Alternative, Western would operate its system as a 
sub-control area within the ISO control area. Western would dispatch 
the internal generation of Reclamation, as needed, to satisfy the needs 
of the sub-control area and to maintain the net scheduled interchange 
with the ISO. Western would schedule the use of its transmission system 
to meet its statutory obligations to Project Use loads and contractual 
obligations to its customers as well as to meet the needs of the sub-
control area and MSS participants in aggregate. Operation of the 
Federal system would not be a concern to the ISO as long as Western 
maintains its scheduled flows with the ISO.
    Scheduling the use of Western's ownership in the Malin-Round 
Mountain transmission line and the COTP would remain Western's 
responsibility and would be performed under NERC and WECC protocols and 
operating procedures developed by the Bonneville Power Administration 
(BPA), the ISO, Western, and others. Under the MSS Alternative, and 
unless otherwise desired, the ISO would continue to remain the single 
path operator for the COI south of the California-Oregon Border (COB).
    Because operation of the Federal system would have to meet the 
terms of the MSS agreement and operating procedures for the COI 
developed under NERC and WECC operating criteria, Western would not be 
able to change the operation of the Federal system unilaterally. 
Western acknowledges that changes in the operation of the Federal 
system would have to be structured to assure that unintended impacts to 
third parties do not occur. Because of these considerations, Western 
concludes that the MSS Alternative meets the operational transparency 
criteria.
Evaluation of the Cost-Effectiveness Criteria Under the MSS Alternative
    Navigant prepared a revised comparative economic benefit analysis 
for each post-2004 operational alternative considered on behalf of 
Reclamation and Western incorporating comments received from the ISO 
and others related to the underlying assumptions used in the study. The 
revised study shows that, comparatively, the cost of the MSS and 
control area alternatives remain similar and that the PTO option 
continues to be the least cost-effective of the three post-2004 
alternatives being considered.
    Commentors during the public process expressed their views about 
the comparative economic study performed by Navigant and the importance 
of the cost effectiveness criteria.
    The TANC commented:

    * * * given the rapid escalation of the CAISO costs, numerous 
inaccuracies of CAISO settlements, and extreme complexity and 
variability of CAISO market design, assumption-based cost forecasts 
in the CAISO environment are difficult to estimate and cannot be the 
most important evaluation criteria for Western and its Customers.

    The TPUD stated:

    The Navigant study and the forthcoming Cal ISO study, which will 
no doubt repudiate most, if not all, of Navigant's work, are a waste 
of time, money and effort. A prediction of how many tariff 
amendments the Cal ISO will file over the next twenty years would be 
more certain than anyone's prediction of the Cal ISO costs just two 
years from now.

    The TID commented:

    Western should not be persuaded to forego the FCA [Federal 
Control Area] option because some indicate that it may not be the 
low cost option. If, as the CAISO, and perhaps others, purport, 
participating in the CAISO is the most cost effective approach, then 
over time, Western customers will migrate to the CAISO market. The 
CAISO has a mission of being the preferred transmission provider. If 
they meet the goal, Western customers will find ways to participate 
and join the CAISO.

    A number of Western's customers were especially concerned about 
increases in their internal costs associated with meeting the billing 
and settlements requirements associated with participating in the ISO 
markets. Increased complexity and the need for

[[Page 67431]]

additional investment in software and other associated equipment and 
infrastructure, as well as additional staff to handle ISO business 
requirements, are all concerns.
    Western views the Navigant study as what it was intended to be; a 
screening study to determine if any one of the alternatives were more 
or less cost-effective than the other alternatives. The revised 
comparative economic studies containing updated assumptions, referenced 
above, continue to indicate that the MSS and Control Area alternatives 
are comparable. Western, therefore, concludes that the MSS Alternative 
meets the cost-effectiveness criteria.
    Under the terms and conditions of Contract 2948A, PG&E agreed to 
provide transmission service to Federal Project Use loads and 
Preference customers instead of the Federal Government constructing its 
own transmission system. Although this contract expires, since PG&E's 
actions precluded the Federal Government from constructing its own 
facilities, Western asserts that PG&E is responsible for assuring the 
delivery of Federal power at rates consistent with its embedded cost of 
service. Any cost increases for transmission service beyond those 
already established under the terms and conditions of Contract 2948A 
constitute a cost-shift to Reclamation's Project Use loads and 
Western's Preference customers. Since PG&E is now paying those costs, 
costs to statewide ratepayers would not increase if the current 
arrangement continues.
Summary Analysis of the MSS Alternative
    The MSS Alternative includes operation of the Federal system as a 
sub-control area within the ISO control area and provides, through 
accounting mechanisms with the ISO, for Western to follow the loads of 
Western's MSS participants. Through the ``net'' settlements treatment 
of the MSS by the ISO, some of the ISO charges for imbalance energy and 
reserves could be avoided by MSS participants. However, off-system 
Project Use loads and Preference customers would still be subject to 
transmission and related charges by the ISO. With the expiration of 
Contract 2948A, the expenses previously paid by PG&E would be shifted 
to off-system customers. These customers would see a significant 
increase in their costs for transmission service.
    Western's off-system Project Use loads and Preference customers 
would be subject to all of the ISO charges associated with transmission 
and delivery of Federal power to them. These charges represent a 
significant increase in costs to Western's off-system customers. Under 
Contract 2948A, PG&E has an obligation to serve the combined PG&E/
Western load under the terms and conditions of the contract. These 
costs are now being paid to the ISO by PG&E under terms of Contract 
2948A but will be charged to Western's off-system customers after 
January 1, 2005. The ``net'' settlement treatment, if these Project Use 
loads and Preference customers are MSS participants, may reduce the 
total cost impact but some cost shifting will occur. Unless successor 
arrangements can be successfully negotiated with PG&E, and/or other 
cost allocation arrangements undertaken, these cost shifts are 
unavoidable under the PTO, MSS, sub-control area, and control area 
alternatives. As part of its formal rate process, Western is 
considering alternatives to minimize these cost shifts to its 
customers.
    From an infrastructure standpoint, the MSS Alternative will still 
require the development and implementation of all of the systems 
described previously in the section entitled, ``Implementing the post-
2004 Power Marketing Plan.'' In addition to these systems, Western will 
have to upgrade its Supervisory Control and Data Acquisition (SCADA) 
system to include an AGC module. From a staffing standpoint, Western 
would have to maintain a 24-hour Merchant Desk and a 24-hour 
Transmission Switching Desk, requiring an estimated 15 positions. The 
Transmission Switching Desk already exists. Western intends to hire the 
Merchant Desk positions from within the organization to the maximum 
extent possible to minimize the need for new staff and to continue 
transforming its organization to meet the needs of its new Marketing 
Plan. Western would have to maintain a 24-hour AGC desk and a 24-hour 
Transmission Scheduling and Security Desk requiring another estimated 
14 positions. Because of the existing staffing levels, Western 
anticipates that it will need to hire only eight new positions to staff 
these three desks (AGC, Transmission Scheduling, and Transmission 
Security) above what is required for the PTO Alternative. Western may 
also need to add additional staff to the Settlements function to 
account for and reconcile ISO and Western charges and issue bills to 
MSS participants for services provided in following load and providing 
reserves for MSS participants. Western estimates it will need an 
additional two positions to accommodate these activities.
    This table summarizes the relative ratings of each evaluation 
criteria for the MSS Alternative:

                   MSS Alternative Evaluation Summary
------------------------------------------------------------------------
                                                       Almost   Does not
            Evaluation  factors               Meets     meets     meet
------------------------------------------------------------------------
Flexibility...............................       XX
Certainty.................................  ........       XX
Durability................................  ........       XX
Operating Transparency....................       XX
Cost-Effectiveness........................       XX
------------------------------------------------------------------------

The Control Area Alternative

    Under this alternative, Western would initiate the control area 
certification process by submitting an application to NERC and WECC. 
This process requires up to 6 months to complete and requires Western 
to document its ability to operate its system reliably under all 
applicable NERC and WECC policies and guidelines. In addition, Western 
must demonstrate its operations will not affect neighboring control 
areas. In the event impacts to neighboring control areas are 
identified, Western must identify and implement sufficient remedial 
measures to mitigate such impacts.
    Once an application is submitted, a review team is selected from 
the WECC membership. The review process includes interviews and/or 
questionnaires of neighboring control areas. This process is designed 
to identify issues that may arise from Western forming a control area. 
Any issues that are identified during the review process must be 
resolved to the satisfaction of WECC before a new control area is 
certified. When the review team is satisfied that Western can operate 
its system reliably within applicable NERC and WECC criteria, the 
review team will recommend to the NERC and WECC Boards of Directors 
that certification status be approved. Western would receive 
certification to operate as a control area only when the review team's 
recommendation is approved by the NERC and WECC Boards of Directors.
    Under this alternative, Western would continue to be responsible 
for operating, maintaining, and replacing the CVP transmission 
facilities. Reclamation would remain responsible for switching, 
maintaining, and replacing the CVP generating facilities. Under this 
alternative, Western would operate as a control area and establish 
control area boundaries with the ISO, the BPA, and

[[Page 67432]]

SMUD. Western would schedule the use of the CVP transmission system and 
Western's Malin-Round Mountain transmission line. If Western continues 
in its roles as the operating agent for COTP, this line would also be 
included within the Western control area and Western would assume 
responsibility for its operational control. As long as it continues as 
COTP's operating agent, Western would continue to provide services to 
maintain and replace these facilities. Western would schedule use of 
the CVP transmission system, the COTP, and the Malin-Round Mountain 
transmission line. The ISO would remain as the single path operator for 
the entire COI.
Operating Scenario To Evaluate the Control Area Alternative
    Under the Control Area Alternative, Western would establish a 
physically defined contiguous system. As a control area operator, 
Western would manage the net power flows through its interconnection 
points with the ISO, BPA, and SMUD under NERC and WECC criteria and 
guidelines. Western would schedule energy deliveries to Project Use 
load, First Preference customers, and other customers, match its 
generation and load, provide reserves, and provide frequency support 
for the WECC interconnection under NERC and WECC criteria and 
generation schedules developed by Reclamation and Western.
    Western would self-provide imbalance energy and ancillary services 
and could participate in the ISO markets whenever excess generation or 
reserves are available. Although off-system customers would not be 
included in the initial control area formation phase, Western 
contemplates discussing the possibility of dynamically scheduling to 
off-system customers with the ISO after sufficient experience is gained 
as a control area operator and the ability of Reclamation's generation 
to follow loads dynamically is ascertained.
    Western's customers directly connected to Western's system would 
not be subject to use of the ISO grid for deliveries of Federal power. 
However, off-system Project Use loads and Preference customers would 
incur all of the ISO transmission and related charges associated with 
the deliveries of Federal power. Western would market transmission 
service to its customers on an open access and non-discriminatory 
basis.
    From an operational perspective, Western would have a 24-hour 
Merchant Desk to purchase energy required for Western's Variable 
Resource and Full Load Service customers and would act as the SC for 
Reclamation's generation and Project Use loads, as well as for 
interested customers. The 24-hour staffing of the Merchant Desk is 
required by the ISO for Western to maintain its SC status, as well as 
to implement its post-2004 Marketing Plan. Western would also maintain 
a 24-hour 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 interconnected systems in 
restoring the system following a disturbance. Since Western would 
schedule the use of its transmission system and those elements of the 
COI it owns or is responsible for under contract, Western would have to 
maintain a 24-hour Transmission Scheduling Desk. To regulate the 
control area, Western would maintain a 24-hour AGC Desk.
    From an organizational perspective, Western would continue to need 
a power accounting, billing, and settlements function to account for 
services purchased and sold, reconcile billings from the ISO and others 
to the accounting records, and issue invoices to Western's customers 
and the ISO. Current staffing levels in the settlements function would 
need to increase by an additional two positions to support the 
additional workload for the Control Area Alternative.
Evaluation of the Flexibility Criteria Under the Control Area 
Alternative
    Under the Control Area Alternative, Western would be required to 
physically establish its boundaries and become a stand-alone unit 
within the WECC interconnection. In forming a control area, Western 
would need to have operational agreements with neighboring control 
areas to assure it would operate its system in concert with neighboring 
systems. These arrangements typically include metering and 
communication agreements, emergency operations procedures, normal 
operating procedures, data exchange arrangements, and power accounting 
procedures. These arrangements comply with NERC and WECC standards.
    As NERC and WECC industry wide standards change, Western would have 
to change its procedures and structure its inter-control area 
agreements to accommodate such industry wide changes. Therefore, short-
term flexibility would be provided for within the construct of the 
inter-control area agreements.
    When, and if, Western chooses to join an RTO, it could do so as a 
stand-alone entity, without the need to terminate any agreement. The 
operating agreements between Western and the neighboring control areas 
would not change, because from a physical standpoint, nothing changes 
if Western joins an RTO. Operational protocols may change, but the 
physical operation of the system must continue. Changes in operational 
protocols would still have to comply with the applicable NERC and WECC 
reliability standards.
    Because of the absence of the need to terminate any agreement, and 
the intended construct of the inter-control area agreements with 
neighboring control areas, Western concludes the Control Area 
Alternative meets the flexibility criteria.
Evaluation of the Certainty Criteria Under the Control Area Alternative
    Under the Control Area Alternative, neither Western nor the direct-
connected customers would be subject to ISO charges except for those 
services purchased from the ISO. Western, however, would charge the 
direct-connected customers for capacity, energy, transmission, and 
ancillary services with rates determined through a public process. 
Western's off-system Project Use loads and Preference customers would 
be subject to ISO charges for transmission and delivery of Federal 
power and ancillary services. Under this alternative, Western intends 
to implement dynamic scheduling after it has sufficient experience 
operating as a control area. Consequently, non-direct connected 
customers may be able to avoid some of the imbalance energy and reserve 
charges of the ISO shortly after the control area is established and 
operational.
    Costs associated with the Control Area Alternative are expected to 
be fairly predictable and include charges for labor and equipment to 
operate, maintain, and replace the CVP transmission facilities of 
Western and the costs allocated to hydropower generation facilities 
owned and operated by Reclamation. These costs have historically been 
included in CVP power rates established by Western. CVP rates are cost 
based and established at the lowest possible rates consistent with 
sound business principles. Additional costs associated with operating a 
control area are purchased power costs necessary to balance the control 
area during the fall and winter months when insufficient generation is 
available to meet Project Use and First Preference loads. Power 
purchased for these purposes is expected to be purchased in the forward 
markets as blocks, rather than purchased on the spot market, to reduce 
price volatility

[[Page 67433]]

and ensure stable rates. With the ongoing development of generation 
optimization tools, Western expects the timing and quantity of 
purchased power amounts can be predicted with reasonable certainty 
after Contract 2948A expires.
    Using the forward purchase approach, the Control Area Alternative 
should limit Western's exposure to the spot market. Because the 
preponderance of Western's costs are within Western's control, CVP 
rates should remain reasonably stable over time, and rate adjustments 
should not be needed more often than that which has historically 
occurred, approximately every 3 years. As a control area, Western would 
be required to meet WECC and NERC operating criteria. To the extent 
Western is not able to fully comply with such criteria, it will be 
subject to financial penalties for non-compliance. Western has 
considered this risk in its decision-making process.
    The ISO is in the midst of implementing new operating guidance for 
its MD02 initiative. This new initiative would implement the concept of 
locational marginal pricing to deal with transmission congestion. If 
MD02 is implemented in its current format during congestion periods, 
the ISO would re-dispatch all generation based on economic factors. 
Under this alternative, CVP Preference customers and Project Use loads 
that remain in the ISO control area could end up paying a different 
price than the cost-of-service 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. Western 
concludes that for control area participants, the Control Area 
Alternative meets the certainty criteria.
    In addition to implementing a new control area, Western is also 
considering the possibility of assessing charges on the PACI associated 
with the cost of off-system deliveries to its customers served via the 
ISO-controlled grid. The intent of Congress, when it authorized the 
construction of the PACI, was to assure that Federal Preference 
customers would receive power as if Federal facilities had been 
constructed. Although this cost would in effect result in rate 
pancaking users of the PACI, Western believes these costs are 
relatively minor and assures that the intent of Congress continues to 
be met. These costs are outside the scope of this process and will be 
discussed as part of the rate process for implementation of the post-
2004 Marketing Plan and the post-2004 Operational Alternative, which is 
scheduled to start February 2004.
Evaluation of the Durability Criteria Under the Control Area 
Alternative
    Under the Control Area Alternative, Western would be subject to 
industry wide changes in operating protocols and business practices 
coordinated by NERC and WECC. These changes generally result from 
policy or standards changes made through industry consensus and 
approved by the NERC and WECC Boards of Directors and, historically, 
have not occurred with great frequency.
    Changes in Western's business practices are generally determined by 
changes in Federal or industry wide policies and may be made through a 
public process designed to assure that the impacts of these changes are 
fully understood by the agency prior to implementing them. Western 
contemplates executing contracts with intra-control area participants. 
These contracts would recognize physical rights and should assure 
reasonable predictability and allow the participants to manage their 
risks and make the appropriate long-term business decisions. Because 
the operating protocols and business practices under the Control Area 
Alternative are controlled by industry consensus or Western's own 
actions, Western concludes that the Control Area Alternative meets the 
durability criteria.
Evaluation of the Operating Transparency Criteria Under the Control 
Area Alternative
    To become a certified control area, Western would have to operate 
under NERC and WECC operating criteria and guidelines. These criteria 
and guidelines require that the operation of Western's system cannot 
impact other control areas. If Western were to change the operation of 
the Federal system, as a control area, it would have to assure such 
changes would not impact third parties or its operation would not 
violate NERC and WECC requirements and consequently be subject to 
financial penalties under the WECC Reliability Management System 
agreement. Because of the requirements within NERC and WECC criteria 
and guidelines to assure no impacts on third parties occur as a result 
of Western's control area operations, Western concludes that the 
Control Area Alternative meets the operating transparency criteria.
Evaluation of the Cost-Effectiveness Criteria Under the Control Area 
Alternative
    Western is considering the possibility of assessing charges on the 
PACI associated with the cost of off-system deliveries to its Project 
Use loads and Preference customers served via the ISO-controlled grid. 
The intent of Congress, when it authorized the construction of the 
PACI, was to assure that Federal Project Use loads and Preference 
customers would receive power as if Federal facilities had been 
constructed. Although this cost would in effect result in rate 
pancaking for PACI users, Western believes these costs are relatively 
minor and assures the intent of Congress continues to be met. These 
costs are outside the scope of this process and will be discussed as 
part of the rate process for implementation of the post-2004 Marketing 
Plan and the post-2004 Operational Alternative, which is scheduled to 
start February 2004.
    Navigant prepared a revised comparative economic benefit analysis 
for each post-2004 operational alternative, which incorporated comments 
received from the ISO and others related to the underlying assumptions 
used in the study. The revised study shows that, comparatively, the 
relative cost of the MSS and Control Area alternatives remain similar. 
The PTO option continues to be the least desirable from a cost 
standpoint of the three post-2004 alternatives under consideration.
    Western reviewed the comments on the Navigant study referenced 
above provided by the ISO and others and made a number of changes to 
the study which are described in the section entitled ``Comparative 
Economic Benefits Study.'' The revised study continues to indicate that 
the MSS and Control Area alternatives are comparable.
    During the public process, commentors offered some views relative 
to the economic studies performed by Navigant and the importance of the 
cost effectiveness criteria.
    The TANC commented:

    * * * given the rapid escalation of the CAISO costs, numerous 
inaccuracies of CAISO settlements, and extreme complexity and 
variability of CAISO market design, assumption-based cost forecasts 
in the CAISO environment are difficult to estimate and cannot be the 
most important evaluation criteria for Western and its customers.

    The TPUD stated:

    The Navigant study and the forthcoming Cal ISO study, which will 
no doubt repudiate most, if not all, of Navigant's work, are a waste 
of time, money and effort. A prediction of how many tariff 
amendments the Cal ISO will file over the next twenty years would be 
more certain than anyone's prediction of the Cal ISO costs just two 
years from now.

    The TID commented:


[[Page 67434]]


    Western should not be persuaded to forego the FCA [Federal 
Control Area] option because some indicate that it may not be the 
low cost option. If, as the CAISO, and perhaps others, purport, 
participating in the CAISO is the most cost effective approach, then 
over time, Western customers will migrate to the CAISO market. The 
CAISO has a mission of being the preferred transmission provider. If 
they meet the goal, Western customers will find ways to participate 
and join the CAISO.

    The ISO and a number of other commentors expressed concern that 
Western has the information it needs to make a fully informed decision, 
and that the decision recognize and incorporate the needs of all the 
parties, and not just a small subset. Western views the Navigant study 
as a screening study to determine the comparative differences between 
the alternatives and to determine which alternatives, if any, are 
clearly better or worse than the others. The study looked at the cost 
of delivering Federal Base Resource to Variable Resource customers, and 
Federal Base Resource and Custom Product power for Full Load Service 
customers to the customers' delivery point(s). Western believes that 
the study used reasonable assumptions and cost data based on 
information available at the time. As a comparative benefit study, the 
results were never intended to be used to identify and allocate cost 
repayment responsibilities. Western is undertaking a separate rate 
process to support the post-2004 operations alternative. The rate 
process is the appropriate forum to discuss cost allocation and 
financial repayment obligations. Western has analyzed the comments and 
determined that the Control Area Alternative meets the cost-
effectiveness criteria.
    Under the terms and conditions of Contract 2948A, PG&E agreed to 
provide transmission service to Federal Project Use and Preference 
customers instead of the Federal Government constructing its own 
transmission system. Although this contract expires, since PG&E's 
actions precluded the Federal Government from constructing its own 
facilities, Western asserts that PG&E is responsible for assuring the 
delivery of Federal power at rates consistent with its embedded cost of 
service. Therefore, any cost increases for transmission service beyond 
those already established under the terms and conditions of Contract 
2948A constitute a cost-shift to Project Use loads and Preference 
customers. Since PG&E is now paying those costs, costs to statewide 
ratepayers would not increase if the current arrangements continue.
Summary Analysis of the Control Area Alternative
    Implementing the Control Area Alternative would allow the Federal 
transmission system to be operated as a NERC and WECC certified control 
area. Customers directly connected to Western's system would avoid ISO 
charges for transmission and related services but would incur similar 
charges from Western. Off-system Project Use loads and Preference 
customers would, however, incur ISO transmission and related charges. 
This would represent a cost shift from the transmission service 
presently provided to off-system Project Use loads and Preference 
customers under Contract 2948A. As discussed under the PTO option, 
these customers are currently provided such transmission service by 
PG&E for Federal power at embedded cost rates. Off-system Project Use 
loads and Preference customers would be subject to all of the ISO 
charges associated with transmission and delivery of Federal power to 
them. These charges represent a significant increase in costs to off-
system Project Use loads and Preference customers. These costs are now 
being paid to the ISO by PG&E currently under terms of Contract 2948A 
but will be charged to Western's off-system customers after January 1, 
2005. Unless successor arrangements can be successfully negotiated with 
PG&E, and/or other cost allocation arrangements undertaken, these cost 
shifts are unavoidable under the PTO, MSS, sub-control area, and 
control area alternatives. As part of its formal rate process, Western 
is considering alternatives to minimize these cost shifts to Project 
Use loads and Preference customers.
    From an infrastructure standpoint, the Control Area Alternative 
would still require the development and implementation of all of the 
systems described earlier in the section entitled, ``Implementing the 
post-2004 Power Marketing Plan.'' In addition to these systems, Western 
would have to upgrade its SCADA system to include an AGC module. From a 
staffing standpoint, Western would have to maintain a 24-hour Merchant 
Desk and a 24-hour Transmission Switching Desk. This requires an 
estimated 15 positions. The Transmission Switching Desk already exists. 
Western intends to hire the Merchant Desk positions from within the 
organization to the maximum extent possible to minimize the need for 
new staff and to continue transforming its organization to meet the 
needs of its new Marketing Plan. Western would have to maintain a 24-
hour AGC desk and a 24-hour Transmission Scheduling and Security Desk 
requiring another estimated 14 positions. Because of existing staffing 
levels, Western anticipates that it will need to hire only eight new 
positions to staff these three desks (AGC, Transmission Switching, and 
Transmission Security) above what is required for the PTO Alternative. 
Staffing within the settlements function to account for, reconcile ISO 
and Western charges, and issue bills to customers is expected to 
increase by two additional positions.
    The comparative economics of the Control Area Alternative are 
described above in the analysis of the PTO Alternative and will not be 
repeated here. That discussion showed that the Control Area Alternative 
is comparable to the MSS Alternative.
    The relative ratings for the Control Area are summarized:

               Control Area Alternative Evaluation Summary
------------------------------------------------------------------------
                                                       Almost   Does not
            Evaluation factors                Meets     meets     meet
------------------------------------------------------------------------
Flexibility...............................       XX
Certainty.................................       XX
Durability................................       XX
Operating Transparency....................       XX
Cost-Effectiveness........................       XX
------------------------------------------------------------------------

Other Operational Alternatives

    A number of commentors recommended Western consider the possibility 
of integrating its operations within an already established WECC 
certified control area such as SMUD. Commentors suggested that such an 
alternative would be similar in concept to the ISO's MSS template, 
except the arrangement would be contract-based, and not tariff-based. 
Western discussed the possibility of a contract-based sub-control area 
with SMUD. SMUD indicated an interest in pursuing additional 
discussions. As part of Western's proposed decision, Western will 
continue discussions with SMUD on forming a contract-based sub-control 
area. Reclamation, as well as the City of Palo Alto, suggested that 
Western consider approaching the ISO to ask about the possibility of 
getting a contract-based sub-control area agreement.
    Sufficient detailed information is not now available to make a 
fully informed judgment to determine how the evaluation criteria would 
apply to this specific alternative and the relative benefits and 
burdens associated with its

[[Page 67435]]

implementation. Western intends to approach the ISO and SMUD to 
initiate discussions and collect additional data to determine the 
feasibility of this alternative. If either alternative is feasible, 
Western will then initiate the appropriate steps to implement it. As 
part of an initial overall review, the following general statements can 
be made.
    From a flexibility viewpoint, the analysis of a contract-based sub-
control area would be similar to the analysis for the MSS Alternative. 
Flexibility would be limited to the termination provisions of the 
agreement putting this alternative in place. Therefore, this 
alternative would probably satisfy the flexibility criteria.
    From a certainty viewpoint, the rates and charges for products and 
services purchased from either control area operator are assumed to be 
contract- and cost-based, rather than market- and tariff-based. 
Therefore, rates should be generally stable and predictable. From that 
perspective, this alternative would probably meet the certainty 
criteria.
    Since this alternative is contingent upon executing a contract-
based agreement, and not dependent on changes to a tariff, the terms 
and conditions should be relatively stable and participants should be 
able to engage and commit to long-range planning activities. This 
alternative would probably meet the durability criteria.
    The operating transparency of an arrangement with either control 
area under this alternative should be seamless. As a contract-based 
sub-control area, Western would operate its facilities within a host 
control area. The host control area must conform its operations to the 
reliability standards outlined by NERC and WECC. Consequently, any 
changes in operational protocols and procedures would have to minimize 
and/or mitigate any impacts and be accomplished in close coordination 
with neighboring control area operators. This alternative would 
probably meet the operating transparency criteria.
    Insufficient information is available to make a preliminary 
determination as to the relative cost-effectiveness of this 
alternative. However, since the SMUD control area operates on a cost-
based orientation, we assume that, at a minimum, it probably meets the 
cost-effectiveness criteria.
    A number of commentors suggested that Western consider a contract-
based MSS arrangement with the ISO. The ISO currently operates under a 
tariff-based system. However, consistent with Western's proposed 
decision, Western intends to initiate discussions with the ISO to 
investigate the feasibility of pursuing this type of an agreement.

Comparison of the Operational Alternatives

    Implementing each alternative under consideration would result in a 
different operational configuration and would result in a different 
relationship with the ISO. Each alternative also subjects Western to 
different staffing levels because of the needs for different functions 
associated with that alternative.
    The No Action Alternative may create a situation where Western is 
unable to perform under its power contracts and places Western in a 
position of scrambling to put arrangements in place to operate the 
Federal system within the ISO control area. Western may also not be 
able to assure project repayment under this alternative. Western would 
essentially be a price and service taker without the ability to 
negotiate favorable terms and conditions because of the impermanent 
nature of the operational agreements. Western has determined that this 
is not a preferable alternative.
    The PTO Alternative would result in Western's system being 
integrated with the ISO control area and all of Western's customers 
being subject to all of the ISO charges for scheduling and delivery of 
Federal power to their delivery points. Western's transmission revenue 
requirement would be met, and its staffing levels under this 
alternative would be the lowest of any of the alternatives. Western's 
rates would have to be set to cover all of the ISO charges associated 
with Western's role as the SC for Reclamation generation.
    The MSS Alternative would allow Western to operate within the ISO 
control area as a sub-control area and would provide accounting 
mechanisms for Western to include all customers desiring to participate 
in the MSS to be included in the MSS. Western's customers may avoid 
some ISO ancillary service charges depending on the ability of the CVP 
generation to follow the combined load of Western's MSS participants. 
The direct-connected Project Use loads and Preference customers would 
also be able to avoid some transmission and related charges, but the 
off-system Project Use loads and Preference customers would not avoid 
transmission and other ISO charges. The charges for the MSS Alternative 
may be lower than under the PTO Alternative because of the ``net'' 
settlements feature of the MSS.
    The Control Area Alternative would allow Western to function as an 
interconnected control area with BPA, the ISO, and SMUD under NERC and 
WECC criteria and guidelines. Direct-connected customers would avoid 
all ISO charges associated with delivery of Federal power, but the off-
system Project Use loads and Preference customers would not avoid these 
charges.
    From an infrastructure viewpoint, all of the systems necessary to 
support the post-2004 Marketing Plan are needed and are independent of 
the alternative chosen. The MSS, control area, or sub-control area 
alternatives all require the addition of an AGC module to Western's 
SCADA system. The MSS, control area, and sub-control area options also 
require the creation of two new 24-hour desks (AGC and the Transmission 
Scheduling and Security Desks) as well as the addition of two staff 
positions in the settlements function. These positions would not be 
required under the PTO option.
    During the public comment period, Western received numerous 
comments from customers and interested stakeholders indicating their 
respective preferences for, or against, a specific post-2004 
operational alternative. A common thread of the comments received from 
Western's customers encouraged Western to choose an alternative that 
did not place Western's relationship with the ISO under the ISO Tariff. 
Reasons cited were the frequency of changes to the ISO Tariff and the 
costs associated with possible litigation over proposed ISO Tariff 
modifications.
    The PTO option subjects Project Use loads and Preference customers 
to all ISO charges. While this option requires the least amount of 
Federal investment in infrastructure and staffing, it subjects all of 
the Project Use loads and Preference customers to all ISO charges. This 
substantially increases cost-of-service rates because the relatively 
low cost of Federal transmission facilities would be blended with 
higher statewide transmission facility costs under this alternative. 
This option also raises concerns related to the operation and control 
over Federal facilities. Specifically, Reclamation and Western would 
have to assure the operation of CVP water and hydropower facilities 
would be consistent with the project's statutory authorizations. Based 
on these factors, Western is removing the PTO option from further 
consideration.
    The MSS option presents some favorable characteristics for Project 
Use loads, Preference customers, and Western. The ability to provide 
some ancillary services to Project Use loads and Preference customers 
that participate in the MSS, subject to the availability of CVP 
generation, and the

[[Page 67436]]

ability to pay ISO charges based on the ``net'' settlements feature 
appear desirable. Western is concerned with the frequent number of 
amendments to the ISO Tariff. Numerous commentors raised concerns about 
the number of ISO Tariff amendments during the public comment period. 
If Western were able to develop a contractual agreement with the ISO 
which does not specifically reference the ISO Tariff, and if the 
contractual agreement contained terms and conditions which would not 
change during the life of the contract, Western would be interested in 
pursuing such an arrangement. Such an arrangement would recognize the 
unique legislated purposes and characteristics of the CVP and would 
maintain an appropriate balance and separation between a State-
controlled and Federal entity. A contract-based MSS option structured 
under these principles, if offered by the ISO, will be considered. The 
impact of the ISO's MD02 activities will need to be addressed also. If 
the ISO cannot accommodate such principles, the MSS option will not be 
considered further.
    The control area option meets all of the decision-making criteria 
outlined by Western. However, operation as a sub-control area within 
the SMUD control area also appears to meet these criteria. The direct-
connected customers would avoid ISO charges for delivery of Federal 
power and would pay Western or the host control area for ancillary 
services associated with such delivery. There are two different 
approaches for sub-control area operations that could provide benefits 
for Western and the host control area. The first is called integrated 
operations and would allow Western to operate within the host control 
area and provide its share of regulation and reserves associated with 
the combined load of Western and the host control area. Accounting 
mechanisms would be put in place to account for services rendered. 
Essentially, this would resemble integrated operation with the host 
control area. The second arrangement is called segregated operations 
and would allow Western to provide reserves and regulation associated 
with its direct-connected customers and firm exports and regulate 
hourly to a net scheduled interchange quantity with the host control 
area. This operation resembles interconnected control area operation, 
but Western would not be accountable to the WECC and NERC.
    The SMUD has expressed interest in establishing a sub-control area 
under a contractual agreement that would contain terms and conditions 
established for the duration of the contract. Because of the seasonal 
nature of the CVP generation resource, a contractual approach to either 
integrated or segregated operation may contain benefits for Project Use 
loads, Preference customers, and Western. Western will pursue this 
further with SMUD.

Other Issues Raised During the Public Process

    The ISO and a number of other commentors raised the following three 
additional issues during the public process. The commentors were 
specifically concerned about the alternative for a new control area and 
raised the following three issues: (1) Adverse implications to grid 
reliability and operations, (2) increased complexity of operating the 
COI, and (3) inconsistency of Western's proposal with existing Federal 
policy and proposed direction.
    Commentors were concerned that the creation of a new control area 
was inconsistent with existing Federal policy, which would result in 
additional complexity and could cause the electrical transmission grid 
to be operated less reliably. Since the proposed decision does not 
contemplate formation of a new control area at this time, these issues 
need not be addressed as part of this Federal Register notice.
    Western's position is that in the event the control area 
alternative is ever selected, as part of the WECC/NERC control area 
certification process, many of the operating issues (grid reliability 
and increased complexity of operations) raised by the commentors would 
be identified, analyzed, and mitigated, if appropriate, as part of the 
control area certification process. These issues would normally be 
handled as a matter of meeting specific technical performance criteria 
rather than policy.

Conclusion

Western's Proposed Action

    Based upon the analysis done with respect to the decision-making 
factors outlined by Western in the June 24, 2003, Federal Register 
notice and further explained at the July 9, 2003, Public Information 
Forum, Western proposes to proceed with its effort to establish a 
contract-based sub-control area within either the ISO or SMUD control 
area. Western is not proposing to form a new control area at this time. 
The complexity and uncertainty of implementing a new marketing plan as 
well as creating a new control area has caused Western to conclude it 
is not prudent to try accomplishing both tasks simultaneously. To 
reduce business risk and uncertainty while establishing a new post-2004 
operational configuration upon the termination of existing contracts, 
Western is proposing to operate its Federal transmission facilities 
within an existing control area. Western will initiate discussions with 
the ISO and SMUD to implement a contract-based sub-control area. This 
option is practical and preserves Western's ability to respond flexibly 
to ongoing changes in the electric utility industry.

Other Considerations

Consistency With Federal Law

    Western will evaluate how Federal law will affect each alternative. 
Western is governed by numerous Federal laws such as the Federal 
Reclamation Law. The Federal Reclamation Law requires Federal power be 
sold to Preference customers. Western implements such sales through a 
Federal marketing plan under the Administrative Procedure Act. The sale 
of Federal power must not impair the primary purposes of the CVP. The 
marketing plans have the full force and effect of law. The alternatives 
must be consistent with Western's obligations under Federal law 
including Western's Marketing Plan. For instance, if Western were to 
become a PTO, it is conceivable that situations could arise where 
Western would be unable to deliver Federal Preference Power to Federal 
customers even where adequate Federal transmission capability was 
available to serve the Federal customer. While the ISO Tariff provides 
a waiver for Federal entities, if a provision of the Tariff conflicts 
with Federal law, Western must still work out the specific details on a 
case-by-case basis whenever such conflicts arise.

Regulatory Procedure Requirements

Regulatory Flexibility Analysis

    The Regulatory Flexibility Act of 1980 (5 U.S.C. 601, et seq.) 
requires Federal agencies to perform a regulatory flexibility analysis 
if a final rule is likely to have a significant economic impact on a 
substantial number of small entities and there is a legal requirement 
to issue a general notice of proposed rulemaking. Western has 
determined that this action does not require a regulatory flexibility 
analysis since it is a rulemaking of particular applicability involving 
services applicable to public property.

Environmental Compliance

    Under the National Environmental Policy Act (NEPA) (42 U.S.C. 4321. 
et seq.), Council on Environmental Quality NEPA implementing 
regulations (40

[[Page 67437]]

CFR 1500-1508), and DOE NEPA implementing regulations (10 CFR 1021), 
Western completed an environmental impact statement (EIS) on its Energy 
Planning and Management Program. The Record of Decision was published 
in the Federal Register (60 FR 53181, October 12, 1995).
    Western also completed the 2004 Power Marketing Program EIS (2004 
EIS), and the Record of Decision was published in the Federal Register 
(62 FR 22934, April 28, 1997). The Marketing Plan falls within the 
range of alternatives considered in the 2004 EIS. This NEPA review 
identified and analyzed environmental effects related to the Marketing 
Plan. Available reservoir storage and water releases controlled by 
Reclamation influences marketable CVP and Washoe project electrical 
capacity and energy. Reclamation completed a programmatic Environmental 
Impact Statement (PEIS) under the CVP Improvement Act of 1992 (Pub. L. 
102-575, Title 34) on October 1999. Actions based on the PEIS may 
result in modifications to CVP facilities and operations that would 
affect the timing and quantity of electric power generated by the CVP. 
Such changes may affect electric power products and services marketed 
by SNR. The Marketing Plan has the flexibility to accommodate these 
changes. Western was a cooperating agency in Reclamation's PEIS 
process.

Determination Under Executive Order 12866

    Western has an exemption from centralized regulatory review under 
Executive Order 12866. No clearance of this notice by the Office of 
Management and Budget is required.

Small Business Regulatory Enforcement Fairness Act

    Western has determined that this rule is exempt from congressional 
notification requirements under 5 U.S.C. 801 because the action is a 
rulemaking of particular applicability relating to services and 
involves matters of procedure.

    Dated: November 21, 2003.
Michael S. Hacskaylo,
Administrator.
[FR Doc. 03-29984 Filed 12-1-03; 8:45 am]
BILLING CODE 6450-01-P