Operational Alternative for Post-2004 Operations

Note: EPA no longer updates this information, but it may be useful as a reference or resource.

[Federal Register: December 2, 2003 (Volume 68, Number 231)]
[Notices]
[Page 67417-67437]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr02de03-53]

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DEPARTMENT OF ENERGY
Western Area Power Administration

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 tcarter@wapa.gov.

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
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[[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]
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Participating Metered Federal
transmission subsystem control area
owner option option options (A-D)
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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
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Subtotal................................................ 3.0 3.7 6.0
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Other One-Time Expenses:
Western Metering............................................ 0.0 0.0 1.0
Reclamation Metering........................................ 1.3 1.3 0.9
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Subtotal................................................ 1.3 1.3 1.9
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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:

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:

The TPUD stated:

The TID commented:

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:

The TPUD stated:

The TID commented:

[[Page 67434]]

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

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