[Federal Register Volume 68, Number 121 (Tuesday, June 24, 2003)]
[Notices]
[Pages 37484-37490]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 03-15885]


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DEPARTMENT OF ENERGY

Western Area Power Administration


Operational Alternatives for Post-2004 Operations

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of intent.

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SUMMARY: The Western Area Power Administration (Western), is a Federal 
power marketing administration within the Department of Energy (DOE) 
and markets Federal power from the Central Valley and Washoe Projects 
through the Sierra Nevada Region (SNR). SNR is implementing a new 
Marketing Plan on January 1, 2005. On December 31, 2004, three existing 
long-term contracts with the Pacific Gas and Electric Company (PG&E) 
expire. To cost effectively implement its new Marketing Plan, SNR 
identified a number of alternative post-2004 operating scenarios. 
Western must select and implement one of these alternatives in a timely 
manner so that customers of SNR will avoid substantial business risk 
and uncertainty and not be subject to increased costs.

DATES: Written comments from entities interested in commenting must be 
received no later than 4 p.m., PDT, August 8, 2003. Western will accept 
written comments received via regular mail through the U.S. Postal 
Service if they are postmarked at least 3 days before August 8, 2003, 
and received no later than August 13, 2003. Entities are encouraged to 
hand deliver or use certified or electronic mail for delivery of 
comments. Western will not consider comments received after the 
prescribed

[[Page 37485]]

date and time. SNR will hold a Public Information Forum to describe the 
alternatives under consideration on July 9, 2003, Folsom, CA, beginning 
at 10 a.m. SNR will also hold a Public Comment Forum on July 30, 2003, 
Folsom, California, at 10 a.m.

ADDRESSES: The Public Information Forum and Public Comment Forum will 
be held at the Lake Natoma Inn, 702 Gold Lake Drive, Folsom, 
California. Written comments should be sent to Tom Carter, Power 
Operations Manager, Western Area Power Administration, Sierra Nevada 
Customer Service Region, 114 Parkshore Drive, Folsom, CA 95630-4710, or 
by electronic mail to [email protected].

FOR FURTHER INFORMATION CONTACT: Tom Carter, Power Operations Manager, 
(916) 353-4427, or by electronic mail at [email protected].

SUPPLEMENTARY INFORMATION:

Authorities

    The Marketing Plan for marketing power by the SNR after 2004, 
published in the Federal Register (64 FR 34417) on June 25, 1999, was 
established pursuant to 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 Project Act of 1939 (43 
U.S.C. 485h(c)); and other acts specifically applicable to the projects 
involved.

Background

    Western is a Federal power marketing administration within DOE and 
published its 2004 Power Marketing Plan (Marketing Plan) for SNR in the 
Federal Register (64 FR 34417) on June 25, 1999. The Marketing Plan 
specifies the terms and conditions under which Western will market 
Federal power from the Central Valley Project (CVP), the Washoe 
Project, and any additional power purchased to supplement Federal 
hydropower generation beginning January 1, 2005. SNR has three long-
term contracts (Contracts 14-06-200-2947A (2947A), 14-06-200-2948A 
(2948A), and 14-06-200-2949A (2949A)) with PG&E expiring on December 
31, 2004. The Southern California Edison Company (SCE) and the San 
Diego Gas and Electric Company (SDG&E) are also parties to Contract 
2947A. The three contracts provide for the integrated and 
interdependent operation of the Federal and PG&E transmission systems. 
PG&E provides transmission services to SNR's customers and Project Use 
loads on the PG&E system, interconnects the section of the Pacific AC 
Intertie (PACI) line owned by Western with PG&E-owned facilities, and 
provides Western with 400 megawatts (MW) of transmission capacity 
rights to and from the Pacific Northwest.
    Under legislation authorizing the construction of the Federal CVP, 
the Federal Government had originally planned to construct Federal 
generation and transmission facilities to serve specific Project Use 
facilities and Preference Power allottees. PG&E proposed an alternative 
solution, which integrated the transmission and generation resources of 
both organizations. PG&E stated that its approach would be more 
economic and would be less costly than if the Federal Government 
undertook construction. This synergistic approach became the basis of 
the relationship between Western and PG&E for more than 50 years. In 
1967, Western and PG&E executed Contracts 2947A, 2948A, and 2949A. 
Contract 2947A provides Western up to 400 MW of priority transmission 
capacity on the PACI transmission system. Under Contract 2948A, PG&E 
integrates the hydro-generation resources of the CVP and Western's 
purchased energy with its resource portfolio to meet the combined PG&E 
and SNR loads. Under this arrangement, PG&E provides firming energy, as 
needed, to support the Project Use loads and SNR's power allocations. 
Contract 2949A interconnects PG&E's transmission system with Western's 
at PG&E's Round Mountain Substation.
    As part of PG&E's overall operational responsibilities under 
Contract 2948A, PG&E provides control area services to support SNR's 
loads. When California restructured its electric utility industry in 
1996 with the passage of Assembly Bill 1890, the California Independent 
System Operator (CAISO) was created and took over operational control 
of the transmission lines of the three investor-owned utilities (PG&E, 
SCE, and SDG&E). The CAISO also assumed control area operator 
responsibilities for the geographic service territory of the three 
investor-owned utilities. Under existing arrangements, PG&E secures 
control area services from the CAISO to meet PG&E's contractual 
obligations for Contract 2948A deliveries.
    PG&E has indicated that after the contracts expire, it will no 
longer provide the services identified in these contracts under the 
same terms and conditions in support of SNR's power marketing program. 
When these three long-term contracts expire on December 31, 2004, PG&E 
has informed Western that SNR must either obtain or self-provide many 
of the control area services currently provided by Contract 2948A for 
Project Use loads and its customers directly connected to the Federal 
transmission system. In addition, SNR will need to initiate new 
scheduling arrangements for Project Use loads, CVP generation, and 
customer allocations served through, or attached to, the CAISO 
controlled-grid. To ensure non-interrupted cost-effective deliveries of 
Federal power, Western is preparing to assume responsibility for 
providing many of these services.
    Beginning January 1, 2005, SNR is assuming that it has the 
responsibility for providing many of the services currently provided by 
PG&E under existing contracts for the delivery of Federal power to 
Project Use loads on both the Federal and PG&E transmission systems. 
Nothing in this notice should be taken as a waiver of Western's rights 
or ability to take other actions to secure service.
    To maintain operational flexibility for the CVP and the Washoe 
Project, as well as to implement the Marketing Plan in a cost-effective 
manner in the post-2004 environment, SNR is considering several 
alternative operating scenarios. One of the alternatives identified by 
SNR is the option of forming a new control area. Other alternatives 
include becoming a CAISO Participating Transmission Owner (TO) or 
operating within the CAISO control area as a sub-control area in a 
manner similar to a Metered Sub-System (MSS). The purpose of this 
notice is to advise interested stakeholders of SNR's potential 
activities and to solicit comments on the alternatives.
    The Marketing Plan describes how SNR will market CVP, the Washoe 
Project, and purchased power resources during the period January 1, 
2005, through December 31, 2024. CVP power facilities include 11 
powerplants with a maximum operating capacity of about 2,044 MW and an 
estimated average annual generation of 4.6 million megawatt hours 
(MWh). The Washoe Project's Stampede Powerplant has a maximum operating 
capacity of 3.65 MW with an estimated annual generation of 10,000 MWh. 
The Sierra Pacific Power Company owns and operates the only 
transmission system available for access to the Stampede Powerplant.
    Each of the alternatives under consideration will expose SNR and 
its customers to a different set of financial and operational risks and 
will require the development of different operating protocols and 
procedures.
    Depending upon the alternative selected, Western may be required to

[[Page 37486]]

purchase, acquire, or construct additional facilities to establish the 
electrical boundaries of its system and provide a contiguous path 
between facilities owned by Western. For instance, Western owns the 94-
circuit-mile Malin-Round Mountain 500-kilovolt (kV) transmission line 
(an integral section of the Pacific Northwest-Pacific Southwest 
Intertie) but does not own the electrical facilities that interconnect 
this line to Round Mountain Substation. Western also does not own the 
transformation facilities between the 500-kV and 230-kV transmission 
lines at Round Mountain Substation or the interconnection facilities 
for the 230-kV transmission lines at the Cottonwood Substation. 
Interconnection facilities for a number of Western-owned transmission 
lines at the Cottonwood Substation are also not owned by Western. The 
scope of the acquisition or construction of new facilities will be 
determined in large part by the point at which SNR defines its control 
area or sub-control area boundaries.

Description of Alternatives

    SNR has identified the following alternative post-2004 operating 
scenarios:
    1. The no-action alternative;
    2. Executing a Transmission Control Agreement (TCA) and becoming a 
CAISO Participating TO;
    3. Executing a sub-control agreement with CAISO similar to its MSS 
concept; or
    4. Forming a Western Electricity Coordinating Council (WECC)/North 
American Electric Reliability Council (NERC) certified control area 
with the U.S. Department of the Interior, Bureau of Reclamation 
(Reclamation) generation and load, and certain other generation and 
load within the proposed control area boundary.

Factors To Be Considered During Decision-Making

    In making a decision as to which post-2004 operational scenario to 
implement, SNR has identified factors that it will use in its decision-
making process. These factors include, but are not limited to:
    1. Flexibility: Preserves the ability of SNR to join a Federal 
Energy Regulatory Commission (FERC) approved and certified Regional 
Transmission Organization (RTO) in the future and to implement other 
industry changes;
    2. Certainty: Assures that cost-of-service rates are stable and 
predictable;
    3. Durability: Operating protocols are well established and subject 
to minimal changes over time;
    4. Operating Transparency: Minimizes operating impacts to third 
parties;
    5. Cost-Effectiveness: Cost shifts are minimized and relative cost-
benefit ratios to SNR's customers will be considered.
    FERC is actively encouraging the formation of RTOs. An RTO is an 
independent transmission system operator, governed by an independent 
board of directors. The RTO is responsible for operating a 
geographically discrete and interconnected regional transmission system 
consistent with prudent utility practices as defined by NERC and WECC. 
The selected alternative must have sufficient flexibility to allow SNR 
to accommodate the possibility of joining an RTO as well as modifying 
its operations to implement other changes in the electric utility 
industry. Although Western is not required to undertake a formal public 
process to select an operating configuration for post-2004 operations, 
Western has determined that it serves the public interest to allow 
interested stakeholders an opportunity to provide comments as Western 
goes through its decision-making process. In arriving at its final 
decision, SNR will accept and evaluate all comments received from 
interested stakeholders and ensure that its decision-making process is 
consistent with all applicable Federal laws, regulations, and 
procedures.

No-Action Alternative

    If this alternative is selected, SNR and Reclamation would not 
execute successor transmission arrangements with PG&E or the CAISO. 
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.

CAISO Participating Transmission Owner

    Under this alternative, SNR, at a minimum, would need to execute a 
TCA, thus transferring operational control of the Federal transmission 
system to the CAISO. SNR would, however, retain responsibility for 
continuing to maintain all of its transmission facilities. Execution of 
the TCA would obligate SNR to conform its maintenance, operations, 
business, and administrative practices to all applicable CAISO 
protocols and procedures provided they do not conflict with existing 
Federal law.
    Transmission revenue requirements associated with annual 
maintenance and capital repayment obligations for the Federal 
transmission system on behalf of SNR would be recovered through the 
CAISO Transmission Access Charge (TAC). In lieu of utility-specific 
cost-of-service rates, Federal transmission system beneficiaries would 
transition to a statewide rate, which represents the melded cost of all 
statewide Participating TO transmission revenue requirements.
    To participate in the CAISO markets, and as the owner of the 
Federal generation assets, Reclamation would have to execute a 
Participating Generator Agreement (PGA). Execution of the PGA would 
allow the CVP to contribute energy and/or ancillary services in excess 
of SNR's existing contractual obligations into the market, if 
available.
    Scheduling power across the Federal system would be done by the 
CAISO under terms governed by the CAISO tariffs. These tariffs are 
intended to afford equal opportunity use of all the existing 
transmission under CAISO control to all market participants. Under the 
existing CAISO Tariff, transmission of CVP generation to Project Use 
loads and SNR's customers will not be afforded any preference. In 
addition, if transmission is constrained; e.g., inter-zonal or intra-
zonal congestion exists, non-Federal generation may be re-dispatched to 
cover loads. As the anticipated Scheduling Coordinator (SC) for 
Reclamation's Project-Use loads and resources, SNR would pay the market 
clearing price for any power deliveries associated with energy 
imbalance costs. Under this scenario, assuming that SNR is the SC for 
both CVP generation and Project-Use loads, power would be scheduled 
from CVP generation to its customers and any excess generation, if 
available, would be bid as reserve (unloaded) capacity into the CAISO 
markets. Any imbalances caused by load deviations would be paid for by 
the SC for Project Use loads and SNR's customers. All revenues from 
sales to the CAISO markets would be applied to meet the repayment 
requirements of the CVP. The revenue requirement for CVP transmission 
will be collected by the CAISO under terms of the TCA.
    From an operational perspective, CVP generation would be scheduled 
into the CAISO control area and the CAISO-controlled grid, including 
Federal

[[Page 37487]]

transmission assets, would be used to deliver Federal power and/or 
purchases to Project Use loads and SNR's customers. Under this 
alternative, the costs associated with energy deliveries to Project Use 
loads and SNR's customers are subject to the hourly CAISO market 
prices, transmission congestion charges, imbalance energy charges, and 
all other charges that the CAISO imposes to cover its costs or to 
collect revenue it must collect for transmission owners. Whenever 
actual load requirements exceed the scheduled amounts, the energy would 
be provided by the CAISO under its energy imbalance program.
    From an organizational perspective, this alternative appears to be 
the easiest to implement. SNR would not need a real-time transmission 
scheduling or an automatic generation control (AGC) desk; however, to 
retain its status as an SC, a 24-hour merchant desk would still need to 
be established. A real-time transmission switching desk to monitor the 
Federal system, perform outage coordination and switching for 
maintenance activities, and coordinate system restoration activities 
would be needed. SNR would also have to maintain a settlements 
organization to account for and bill various charges associated with 
purchases and deliveries for customers for which SNR is designated as 
the SC and to reconcile and account for revenues associated with 
generation sales into the CAISO markets.
    The impact of implementing this alternative would effectively 
increase the cost of transmission to all SNR customers. The 
differential would be most pronounced for those entities directly 
connected to the Federal transmission system. Integrating the Federal 
transmission system into the CAISO-controlled grid would result in an 
integrated TAC. However, since many of the direct-connected 
transmission users' transactions do not involve the use of the CAISO-
controlled grid, direct-connected customers could end up paying for 
service that they would not necessarily need under other alternatives. 
Non-direct-connected customers would pay the non-discriminatory rate 
associated with the use of the CAISO-controlled grid. The net effect is 
that the overall average cost of transmission service could decrease 
for the rest of the existing CAISO market participants.

Executing an MSS Agreement With the CAISO

    In lieu of becoming a Participating TO, the CAISO has offered SNR 
the option of becoming an MSS. The CAISO defines an MSS as the system 
of a transmission owner bounded by CAISO-certified revenue quality 
meters at each interface point and generating units internal to that 
metered system. Under this alternative, SNR and Reclamation will need 
to define the physical boundaries of the MSS, ensure the appropriate 
revenue quality meters are present at each interface point and the 
generators, and ensure the appropriate communications and telemetry are 
in place. Since the MSS concept recognizes internal generation, 
Reclamation will not need to execute a PGA. To minimize the cost of 
receiving services from the CAISO markets, SNR will need to balance its 
energy and ancillary services obligations on a continuous basis. This 
function will require a 24-hour per day balancing authority or an AGC 
desk. To minimize costs associated with deviations between actual loads 
and resources, a 24-hour merchant desk is required. To become an MSS, 
SNR would need to negotiate and execute an MSS agreement with the 
CAISO.
    The MSS and the control area alternatives are very similar from an 
operational perspective. Both a control area and an MSS must define 
their boundaries at interconnections with others and both must have the 
ability to use the physical electrical path across these boundaries. 
The proposed transmission system boundaries for both the control area 
and the MSS can be viewed at the following Web site location: http://www.wapa.gov/sn/P04/PDF/SNR-Boundary-06-02-03.PDF
    The northern boundary for the MSS alternative could change. Under 
the MSS alternative, Western would propose to put its Malin-Round 
Mountain transmission line in the CAISO control area and put its 
northern boundary at the 230-kV at the Round Mountain Substation on the 
Round Mountain-Cottonwood transmission line. Transmission scheduling 
between Malin and Round Mountain under the MSS alternative could be 
done by the CAISO while scheduling of transmission between Captain Jack 
and Tracy could be done by SNR. Western would still retain its existing 
capacity rights under a successor arrangement. The CAISO would remain 
the path operator for Path 66, the interface between the California-
Oregon Border and Northern California, with the ability to curtail 
schedules on these paths if reliability is jeopardized.
    An MSS is responsible for matching its internal loads and exports 
with generation and imports on an interval defined in the MSS agreement 
with the CAISO (not necessarily second-by-second). The MSS must 
maintain reserves in an amount that the MSS load bears to the entire 
load of the CAISO control area as defined in the MSS Agreement with the 
CAISO multiplied by the CAISO control area largest hazard (not 
necessarily the MSS largest hazard). The MSS does not have any 
responsibility to maintain the frequency of interconnection. This 
responsibility rests with the CAISO as the control area operator. The 
technical requirements for MSS performance are defined by the MSS 
Agreement with the CAISO. These requirements may change due to the 
CAISO Tariff revisions.
    The CAISO's April 8, 2003, MSS proposal to SNR included the 
following key principles:
    1. The MSS methodology would model SNR's service territory to 
include the entities directly connected to its transmission system 
unless these entities did not want to be included for scheduling and 
settlement purposes. The California-Oregon Transmission Project (COTP) 
line would also be included in SNR's MSS. An accommodation would have 
to be made for CAISO's share of COTP capacity rights currently owned by 
PG&E.
    2. The CAISO would provide ``Net'' Settlements treatment for 
various CAISO market charges, as appropriate, based on cost causation 
principles.
    3. No PG&E Unaccounted-for Energy (UFE) charge would be applied to 
load within SNR's territory.
    4. SNR has the option of choosing to follow MSS load with MSS 
generation to minimize uninstructed energy deviation costs. Penalties 
would apply to all uninstructed deviations. The CAISO has also 
suggested that SNR could include entities not directly connected to its 
transmission system within the MSS and follow those loads with CVP 
generation.
    5. SNR and Reclamation would have the ability to schedule 
customized combinations of MSS resources on a System Unit basis 
(aggregating resources for scheduling and settlements) to provide 
Reclamation with flexibility in dispatching individual generating 
resources.
    6. Reclamation would not have to file a PGA, and Reclamation and 
SNR would have full access to all CAISO markets and associated 
services.
    7. SNR would have the option of using multiple individual 
scheduling identifiers, as required, to facilitate and simplify CAISO 
settlements for SNR SC customers located on the CAISO grid but which 
are external to, and scheduled separately from, the Western MSS.

[[Page 37488]]

    8. Ancillary services obligations would be based on a load ratio 
share of the CAISO ancillary services requirement.
    9. Control area services would be provided by the CAISO.
    Under the CAISO MSS proposal, SNR would, in essence, be a sub-
control area operating within the CAISO control area with the AGC 
system operating in the flat tie-line mode. This means that the AGC 
algorithms would not contain a component to assist in the frequency 
support of the interconnection. SNR would regulate generation internal 
to the MSS so that the net actual interchange (net power flows to the 
CAISO and interconnected control areas) matches the net scheduled 
interchange.
    From a transmission scheduling perspective, the MSS option requires 
SNR to schedule deliveries across the COTP line but not the Malin-Round 
Mountain line. Currently, these schedules are done between the CAISO 
and the Bonneville Power Administration (BPA). Implementation of the 
MSS option, including scheduling the use of transmission from the 
Pacific Northwest, will require coordination between SNR, CAISO, and 
BPA.

Forming a New Control Area

    A control area is a specifically defined geographic region where 
responsibility for continuously matching generation and load is in 
accordance with NERC and WECC planning and operating criteria. A 
control area operator is responsible for continuously monitoring and 
balancing its resources against its load obligations and providing 
frequency support to the interconnected system. The control area 
operator must meet scheduled interchange requirements with other 
control areas, assist in maintaining the frequency of the electric 
power system, and provide sufficient generating capacity to maintain 
operating reserves. The control area operator must also ensure that it 
operates its transmission system in concert with other transmission 
providers in the area to maintain the reliability of the interconnected 
electric system.
    Under this alternative, SNR would establish boundary and interface 
points with neighboring control areas; e.g., BPA, CAISO, the Sacramento 
Municipal Utility District, and others, and install the appropriate 
metering and communication telemetry systems. In addition to the 24-
hour merchant desk and the AGC desk identified under the MSS option 
previously, a transmission scheduling and security desk is also needed. 
Implementation of this option requires negotiating and executing 
additional agreements with the reliability coordinator, as well as 
inter-control area agreements with neighboring entities and intra-
control area agreements with proposed control area participants. In the 
event that significant changes occur to the operation of the three-line 
California-Oregon Interconnect (COI) system, it may also be necessary 
to negotiate modifications to the COI's Coordinated Operations 
Agreement.
    A control area is responsible for matching its internal load and 
exports with generation and imports on a second-by-second basis, for 
maintaining adequate reserves to cover its largest hazard, and to 
assist in maintaining the frequency of the interconnection. The 
technical requirements of the control area are contained in various 
NERC and WECC guidelines and standards; as such, these guidelines and 
standards may change due to industry consensus.
    The control area alternative requires SNR to apply to NERC and WECC 
to become a certified control area. This requires SNR to demonstrate 
that it can meet all of the NERC and WECC planning and operational 
standards and requirements. The control area alternative has, as key 
principles, the following:
    1. The proposed transmission system boundaries for the control area 
are shown at: http://www.wapa.gov/sn/P04/PDF/SNR-Boundary-06-02-03.PDF 
and initially will include those entities directly connected to the 
Federal transmission system. These loads include the cities of Redding, 
Roseville, and Shasta Lake; the Lawrence Livermore National Laboratory; 
Reclamation's Tracy Pumping Plants; the Sutter Energy Center; the East 
Contra Costa Irrigation District; and the Contra Costa Water District. 
The Malin-Round Mountain line and the COTP line would also be included 
in the proposed control area. All CVP hydro-generation directly 
connected to the Federal transmission system will be located within the 
control area.
    2. Customers located within the control area will receive their 
allocation through internal control area schedules and will not 
experience any of the CAISO charges associated with those deliveries. 
Customers located on the CAISO grid will be assessed charges for 
delivery of their allocations associated with the use of the CAISO-
controlled grid, ancillary services charges, transmission distribution 
charges, and other CAISO charges.
    3. No PG&E UFE charges will apply to deliveries of Federal power to 
entities within the control area.
    4. SNR will only follow the load for entities located within the 
control area. After becoming more experienced with control area 
operations, SNR will dynamically schedule generation through the CAISO 
system for interested entities to provide load following for customers 
that are not directly connected. This will minimize the CAISO imbalance 
energy charges for the off-system customers. Entities for which SNR 
provides load following services should not experience significant 
imbalance energy charges from the CAISO. These entities will, however, 
be charged for load following services.
    5. Reclamation will have the flexibility to move water releases 
around their system as needed and will provide the generation levels 
scheduled for delivery internal to the control area and to the CAISO 
control area based on preschedules. There will be no uninstructed 
deviation charges associated with the control area alternative.
    6. SNR expects to be the SC for Reclamation generation and for the 
loads of some of its customers and, therefore, would still participate 
in the CAISO markets under the control area alternative.
    7. Schedules to customers located within the CAISO control area 
will be performed as SC-to-SC trades no differently than many of the 
deliveries of Federal power are made today.
    8. SNR's reserve obligations will be shared by entities directly 
connected to the Federal transmission system in proportion to the load 
of each of these entities within the control area. This is the same 
approach (the load ratio share) as proposed by the CAISO in the MSS 
option. Regulation will be provided to the control area by CVP 
generation with the energy to be returned by those receiving such 
services.
    9. All of the control area services outlined by the CAISO in the 
MSS alternative proposal will be provided by SNR under the control area 
alternative to entities within the control area.
    SNR would regulate internal generation so that the net actual 
interchange matches the net scheduled interchange. Under the control 
area alternative, scheduling over the Malin-Round Mountain and the 
Captain Jack-Tracy paths would be done by SNR. SNR would begin load 
following for its internal customers when control area operations begin 
(January 1, 2005), and would request dynamic scheduling capability for 
off-system customers through the CAISO approximately 6 months later.
    Transmission scheduling for deliveries across the COTP line and for

[[Page 37489]]

the Malin-Round Mountain transmission line would continue to be 
coordinated between CAISO and BPA. Western recommends that under this 
alternative, the CAISO continue as the path operator for the COI, with 
full visibility for all the schedules and the ability to curtail 
schedules if reliability is threatened.

Other Considerations

    In determining which alternative to implement, a major 
consideration for SNR and its customers is the cost of each 
alternative. Under the Participating TO alternative, customers would be 
subject to CAISO charges associated with deliveries of Federal power. 
Under the MSS alternative, certain CAISO charges would be avoided if a 
customer is included in the MSS. Under the control area alternative, 
certain CAISO charges would be avoided by customers within the control 
area and possibly imbalance charges can be avoided through the use of 
dynamic scheduling for off-system customers. The costs and benefits of 
each option are being assessed through a study being performed by a 
consultant for Reclamation. The results of this study are expected to 
be available by the time the Public Information Forum announced in this 
notice is held.
    Implementing the MSS alternative would result in different cost-of-
service rates for transmission service for entities directly connected 
to the Federal transmission system and those entities served from the 
CAISO-controlled grid. In some instances, the expected increase in 
costs, especially for Federal end use loads served on the CAISO-
controlled grid, could be substantial. Since the CAISO levies charges 
based on the net load in its MSS option, there may be certain 
opportunities to use Federal hydropower resources of the CVP to meet 
load requirements of the MSS participants and, thus, mitigate any cost 
increases associated with the use of the CAISO-controlled grid. From 
the standpoint of the CAISO, implementation of this option would keep 
most of its existing operating procedures intact and would ensure that 
its costs are recovered from CVP users.
    If the control area formation option is selected, there still could 
be impacts to others even though mitigation efforts are undertaken. 
Scheduling and operational complexity associated with management of the 
three-line COI system could result. SNR recommends that the CAISO 
continue to serve as the single Path Operator for the COI for 
operational continuity and to assure that impacts are minimized to the 
maximum extent possible.
    Under the control area formation proposal, differential 
transmission rates could still accrue between customers directly 
connected to the Federal transmission system and those who are served 
by the CAISO-controlled grid. If cost-of-service rates to CAISO-
controlled grid users are mitigated, this would result in cost shifts 
to others. Cost shifts could result to other users connected directly 
to the Federal transmission system or to entities seeking transmission 
service either on or through Western's transmission system to the 
CAISO-controlled grid. Finally, to the extent that a new control area 
is formed, fixed expenses associated with operation of the CAISO would 
have to be recovered from a smaller base and, consequently, average 
unit costs for the remaining participants in the CAISO could increase.
    Representatives from SNR will describe the above alternatives and 
the results of the cost/benefit study at the Public Information Forum. 
Western will accept public comments on the alternatives presented at 
the Public Comment Forum. SNR will accept additional written comments 
until the end of the comment period.

Consistency with Federal Law

    Western will evaluate how Federal law will impact each of the 
alternatives. Western is governed by numerous Federal laws such as the 
Federal Reclamation Law. The Federal Reclamation Law requires the sale 
of 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 Participating TO, 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 CAISO Tariff provides a waiver for Federal entities if a 
provision of the Tariff conflicts with the 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 CFR part 1500-1508), and DOE NEPA implementing 
regulations (10 CFR part 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 influence 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 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; accordingly, 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.

[[Page 37490]]

801 because the action is a rulemaking of particular applicability 
relating to services and involves matters of procedure.

    Dated: June 12, 2003.
Michael S. Hacskaylo,
Administrator.
[FR Doc. 03-15885 Filed 6-23-03; 8:45 am]
BILLING CODE 6450-01-P