[Federal Register Volume 65, Number 217 (Wednesday, November 8, 2000)]
[Notices]
[Pages 66989-66995]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-28626]


-----------------------------------------------------------------------

DEPARTMENT OF ENERGY

Western Area Power Administration


Proposed Rates for the Central Valley and California-Oregon 
Transmission Projects

AGENCY: Western Area Power Administration, DOE.

[[Page 66990]]


ACTION: Notice of Proposed Rates.

-----------------------------------------------------------------------

SUMMARY: The Western Area Power Administration (Western) is proposing 
new rates for Central Valley Project (CVP) firm power, power 
scheduling, scheduling coordinator, transmission, California-Oregon 
Transmission Project (COTP) transmission, and CVP ancillary services. 
The current rates expire September 30, 2002. The current power rates 
are insufficient due to significant increases in the prices of energy 
in the California electric markets. Proposing new rates for all the 
services listed above extends the rates for these services through the 
end of the current CVP Power Marketing Plan.
    A rate increase will provide sufficient revenue to repay all annual 
costs, including interest expense, and repay required investment within 
the allowable period. Rate impacts are detailed in a rate brochure to 
be provided to all interested parties. The proposed new rates are 
scheduled to go into effect on April 1, 2001, and will remain in effect 
through December 31, 2004, which is the end of the current CVP Power 
Marketing Plan. This Federal Register notice initiates the public 
process to replace the existing approved rates that expire September 
30, 2002.
    Western previously proposed rates that were published in the 
Federal Register, March 3, 2000. The publication of this Federal 
Register notice rescinds those proposed rates. Western will disregard 
all public input associated with the rescinded proposed rates.

DATES: The consultation and comment period will begin November 8, 2000 
and will end December 29, 2000. Western will present a detailed 
explanation of these new proposed rates at a public information forum 
scheduled for November 17, 2000, beginning at 1 p.m. Pacific Standard 
Time (PST), at the Sierra Nevada Regional Office. Western will receive 
oral and written comments at a public comment forum scheduled for 
December 13, 2000, beginning at 1 p.m. PST, at the Sierra Nevada 
Regional Office. Western must receive all comments by the end of the 
consultation and comment period to assure consideration of the 
comments.

ADDRESSES: Send written comments to Mr. Jerry W. Toenyes, Regional 
Manager, Sierra Nevada Customer Service Region, Western Area Power 
Administration, 114 Parkshore Drive, Folsom, CA 95630-4710, e-mail 
<a href="/cdn-cgi/l/email-protection#6f1b000a01160a1c2f180e1f0e41080019"><span class="__cf_email__" data-cfemail="c9bda6aca7b0acba89bea8b9a8e7aea6bf">[email protected]</span></a>.

FOR FURTHER INFORMATION CONTACT: Ms. Debbie Dietz, Rates Manager, 
Sierra Nevada Customer Service Region, Western Area Power 
Administration, 114 Parkshore Drive, Folsom, CA 95630-4710, (916) 353-
4453, e-mail <a href="/cdn-cgi/l/email-protection#99fdfdf0fcede3d9eef8e9f8b7fef6ef"><span class="__cf_email__" data-cfemail="cca8a8a5a9b8b68cbbadbcade2aba3ba">[email protected]</span></a>.

SUPPLEMENTARY INFORMATION: With the publication of this notice Western 
is withdrawing the previously proposed rates published on March 3, 2000 
(65 FR 11569). Due to significant unexpected increases in the prices of 
energy in the California electric markets, the rates proposed in the 
March 3, 2000, Federal Register notice would be insufficient to recover 
the project costs. Therefore, Western rescinds those proposed rates and 
will disregard all public input associated with the rescinded proposed 
rates.
    This Federal Register notice will initiate the public process to 
replace the existing approved rates that expire September 30, 2002. The 
proposed new rates for CVP firm power are designed to recover an annual 
revenue requirement that includes the investment repayment, interest, 
purchase power costs, transmission, operation and maintenance expense, 
and any charges or credits associated with the creation, termination, 
or modification to any tariff, contract, or schedule approved by the 
Federal Energy Regulatory Commission (FERC). A cost-of-service study 
allocates the projected annual revenue requirement for firm power 
between capacity and energy.
    The capacity revenue requirement includes: (i) 100 percent of 
capacity purchase costs; (ii) 50 percent of the investment repayment; 
(iii) 50 percent of the interest expense; (iv) 50 percent of the 
operation and maintenance expense allocated to power; and (v) 100 
percent of CVP and COTP transmission expense. Projected CVP and COTP 
transmission revenue and 50 percent of projected CVP project use 
revenue reduce the annual costs that determine the capacity revenue 
requirement.
    The energy revenue requirement includes: (i) 100 percent of energy 
purchase costs; (ii) 50 percent of the investment repayment; (iii) 50 
percent of the interest expense; and (iv) 50 percent of the operation 
and maintenance expense allocated to power. Projected surplus power 
revenue and 50 percent of projected CVP project use revenue reduce 
annual costs to determine the energy revenue requirement.
    The resulting capacity/energy revenue requirement split varies from 
30 percent allocated to capacity from April 1, 2001, through September 
30, 2001, to 15 percent allocated to capacity from October 1, 2004, 
through December 31, 2004. The average capacity/energy revenue 
requirement split for the rate period is 22 percent to capacity and 78 
percent to energy. The variation in the capacity/energy revenue 
requirement split is due to fluctuations in energy purchase costs and 
seasonal CVP hydro generation.
    Western also developed new proposed rates for CVP firm power with 
the transmission revenue requirement removed from the firm power 
revenue requirement. These rates would apply if Western joins the 
California Independent System Operator (CAISO) and if the CAISO uses 
the transmission revenue requirement to develop a regional transmission 
rate. Western has not made a decision on joining the CAISO. The 
decision to join the CAISO is not part of this rate adjustment public 
process. These new proposed power rates with the transmission revenue 
requirement removed are designed to recover an annual revenue 
requirement that includes investment repayment, interest, purchase 
power, operation and maintenance expense, and any charges or credits 
associated with the creation, termination, or modification to any 
tariff, contract, or schedule approved by FERC.
    A cost-of-service study allocates projected annual revenue 
requirement for firm power between capacity and energy. The capacity 
revenue requirement includes: (i) 100 percent of capacity purchase 
costs; (ii) 50 percent of the investment repayment; (iii) 50 percent of 
the interest expense; and (iv) 50 percent of the operation and 
maintenance expense allocated to power.
    Fifty percent of the projected CVP project use revenue reduces the 
annual cost to determine the capacity revenue requirement. The energy 
revenue requirement includes: (i) 100 percent of energy purchase costs; 
(ii) 50 percent of the investment repayment; (iii) 50 percent of the 
interest expense; and (iv) 50 percent of the operation and maintenance 
expense allocated to power. Projected surplus power revenue and 50 
percent of the projected CVP project use revenue reduce the annual cost 
to determine the energy revenue requirement.
    The resulting capacity/energy revenue requirement split varies from 
24 percent allocated to capacity from April 1, 2001, through September 
30, 2001, to 11 percent allocated to capacity from October 1, 2004, 
through December 31, 2004. The average capacity/energy revenue 
requirement split for the rate period is 17 percent to capacity and 83 
percent to energy. The variation in the

[[Page 66991]]

capacity/energy revenue requirement split is due to fluctuations in 
energy purchase costs and seasonal CVP hydro generation.
    For both sets of firm power rates described above, Western will 
pass through to its customers any additional costs or credits that may 
be charged or credited to Western as the result of the creation, 
termination, or modification of any tariff, contract, schedule or other 
documents approved by FERC. When possible, Western will pass through 
directly to each customer FERC approved costs or credits in the same 
manner Western receives these costs or credits. If the FERC approved 
costs or credits are charged to Western in such a way that a direct 
pass through to each customer is not possible, Western will distribute 
the FERC approved costs or credits to each customer in a manner 
consistent with the rate design used in developing the proposed rates.
    The new proposed rates for CVP firm power and the applicable 
revenue requirement split between capacity and energy are in Table 1.

                   Table 1.--Proposed Firm Power Rates
------------------------------------------------------------------------
                                Total    Capacity   Energy    Capacity/
      Effective period        composite     $/      mills/      energy
                              mills/kWh   kWmonth     kWh       split
------------------------------------------------------------------------
04/01/01 to 09/30/01........      22.71      3.81     15.99        30/70
10/01/01 to 09/30/02........      26.16      3.34     20.64        21/79
10/01/02 to 09/30/03........      26.96      3.48     21.24        21/79
10/01/03 to 09/30/04........      26.46      3.41     20.85        21/79
10/01/04 to 12/31/04........      29.62      2.96     25.06        15/85
------------------------------------------------------------------------

    The proposed rates for CVP firm power with the transmission revenue 
requirement removed and applicable revenue requirement split between 
capacity and energy are in Table 1A.

   Table 1A.--Proposed Firm Power Rates With the Transmission Revenue
       Requirement Removed From the Firm Power Revenue Requirement
------------------------------------------------------------------------
                                  Total    Capacity   Energy   Capacity/
       Effective period         composite     $/      mills/     energy
                                mills/kWh   kWmonth     kWh      split
------------------------------------------------------------------------
04/01/01 to 09/30/01..........      21.04      2.86     15.99   24/76
10/01/01 to 09/30/02..........      24.74      2.48     20.64   17/83
10/01/02 to 09/30/03..........      25.57      2.63     21.24   17/83
10/01/03 to 09/30/04..........      25.08      2.57     20.85   17/83
10/01/04 to 12/31/04..........      28.22      2.05     25.06   11/89
------------------------------------------------------------------------

    The Deputy Secretary of the Department of Energy (DOE), approved 
the existing Rate Schedule CV-F9 for CVP commercial firm power on 
September 19, 1997 (Rate Order No. WAPA-77, 62 FR 50924, September 29, 
1997). FERC confirmed and approved the rate schedule on January 8, 
1998, under FERC Docket No. EF97-5011-000 (82 FERC para. 62,006). The 
existing Rate Schedule CV-F9 became effective on October 1, 1997, for 
the period ending September 30, 2002. Under Rate Schedule CV-F9, the 
composite rate on October 1, 2000, is 18.56 mills per kilowatthour 
(mills/kWh), the base energy rate is 10.51 mills/kWh and the capacity 
rate is $3.81 per kilowattmonth (kWmonth).
    The proposed rates for CVP firm power will result in an overall 
composite rate increase of approximately 22 percent on April 1, 2001, 
when compared with the current CVP commercial firm power rates under 
Rate Schedule CV-F9. Table 2 provides a comparison of the current rates 
in Rate Schedule CV-F9 and the proposed rates along with the percentage 
change in the rates.

                               Table 2.--Comparison of Current and Proposed Rates
----------------------------------------------------------------------------------------------------------------
                                                          Total             Capacity            Energy
                   Effective period                     composite  Percent    $/kW    Percent   mills/   Percent
                                                           rate     change    month    change     kWh     change
----------------------------------------------------------------------------------------------------------------
                                      Percentage Change in Firm Power Rates
----------------------------------------------------------------------------------------------------------------
                                              Current Rate Schedule
----------------------------------------------------------------------------------------------------------------
Existing 10/01/00 to 09/30/01.........................      18.56  .......      3.81  .......     10.51  .......
----------------------------------------------------------------------------------------------------------------

[[Page 66992]]

 
                                                 Proposed Rates
----------------------------------------------------------------------------------------------------------------
04/01/01 to 09/30/01..................................      22.71      22       3.81       0      15.99      52
10/01/01 to 09/30/02..................................      26.16      41       3.34     -12      20.64      96
10/01/02 to 09/30/03..................................      26.96      45       3.48      -9      21.24     102
10/01/03 to 09/30/04..................................      26.46      43       3.41     -10      20.85      98
10/01/04 to 12/31/04..................................      29.62      60       2.96     -22      25.06     138
----------------------------------------------------------------------------------------------------------------

    The proposed rates for CVP firm power with the transmission revenue 
requirement removed will result in an overall composite rate increase 
of approximately 13 percent on April 1, 2001, when compared with the 
current CVP commercial firm power rates under Rate Schedule CV-F9. 
Table 2A provides a comparison of the current rates in Rate Schedule 
CV-F9 and the proposed rates with the Transmission Revenue Requirement 
removed along with the percentage change in the rates.

    Table 2A.--Comparison of Current and Proposed Rates With the Transmission Revenue Requirement Removed \1\
----------------------------------------------------------------------------------------------------------------
                                                          Total             Capacity            Energy
                   Effective period                     composite  Percent    $/kW    Percent   mills/   Percent
                                                           rate     change    month    change     kWh     change
----------------------------------------------------------------------------------------------------------------
                                      Percentage Change in Firm Power Rates
----------------------------------------------------------------------------------------------------------------
                                              Current Rate Schedule
----------------------------------------------------------------------------------------------------------------
Existing 10/01/00 to 09/30/01.........................      18.56  .......      3.81  .......     10.51  .......
----------------------------------------------------------------------------------------------------------------
                        Proposed Rates With the Transmission Revenue Requirement Removed
----------------------------------------------------------------------------------------------------------------
04/01/01 to 09/30/01..................................      21.04      13       2.86     -25      15.99      52
10/01/01 to 09/30/02..................................      24.74      33       2.48     -35      20.64      96
10/01/02 to 09/30/03..................................      25.57      38       2.63     -31      21.24     102
10/01/03 to 09/30/04..................................      25.08      35       2.57     -33      20.85      98
10/01/04 to 12/31/04..................................      28.22      52       2.05     -46      25.06    138
----------------------------------------------------------------------------------------------------------------
\1\ These rates do not include the cost of transmission; therefore, the customer is required to buy transmission
  at an additional cost.

Adjustment Clauses Associated With the Proposed Rates for CVP Firm 
Power

Power Factor Adjustment

    This provision in Rate Schedule CV-F9 will remain the same under 
the proposed rates for CVP firm power.

Low Voltage Loss Adjustment

    This provision in Rate Schedule CV-F9 will remain the same under 
the proposed rates for CVP firm power.

Revenue Adjustment

    The Revenue Adjustment Clause (RAC) provides for a comparison 
between the projected net revenues in the rate adjustment power 
repayment study to the actual net revenues. If the actual net revenue 
is more than the projected net revenue, CVP preference customers 
receive a credit. If actual net revenue is less than the projected net 
revenue, CVP preference customers may pay a surcharge, if needed, to 
make a minimum investment payment. The limit for the RAC credit or 
surcharge is $20 million, plus any purchase power contract adjustments 
during the fiscal year (FY) for which the RAC is being calculated.
    The RAC is calculated annually and the associated distribution of 
the RAC credit or surcharge occurs during a 9-month period on power 
bills issued January through September. For customers whose RAC credits 
cannot be fully credited through nine equal monthly amounts, Western 
has the option to increase the RAC credit during August and September. 
The FY 2001 RAC calculation will be based on the net revenue for FY 
2001, including revenues and expenses for October 2000 to March 2001, 
which is outside of the rate adjustment period. A RAC will be 
calculated for October through December 2004. The maximum RAC credit or 
surcharge for October through December 2004 is $10 million plus 
purchase power contract adjustments applied to the April to September 
2005 bills.

Proposed Rate for Power Scheduling Service

    The proposed rate for power scheduling service is $76.65 per hour 
and is based on costs incurred to provide the service. Power scheduling 
service provides for scheduling resources to meet load and reserve 
requirements.

Proposed Rate for Scheduling Coordinator Service

    The proposed rate for scheduling coordinator service is $76.65 per 
hour and is based on costs incurred to provide the service. Scheduling 
coordinator service provides scheduling, real-time dispatching, and 
financial settlements with the CAISO and/or power exchanges.

[[Page 66993]]

Proposed Formula Rate for CVP Transmission

    The proposed formula rate for firm CVP transmission includes two 
components:

Component 1: Transmission revenue requirement/(CVP capacity + total 
transmission capacity under long-term contracts). Component 1 is the 
ratio of Western's transmission revenue requirement to the sum of the 
maximum operating capacity of the Northern CVP power plants under 
normal operating conditions (CVP capacity) and the total transmission 
capacity under long-term contracts between Western and other parties. 
Northern CVP power plants are J.F. Carr, Folsom, Keswick, Nimbus, 
Shasta, Spring Creek, and Trinity.
Component 2: Pass through of any transmission-related costs or credits 
incurred by Western due to electric industry restructuring or other 
changes in the industry. The costs or credits in component 2, as well 
as any changes to these costs or credits, will be passed through to 
each appropriate transmission customer.
    Western will revise the rate from component 1 based on updated data 
as of April 30 of each year. Western will also revise the rate from 
component 1 if there is a change in component 1 of the CVP firm 
transmission rate of at least $.05 per kWmonth. The estimated rate 
resulting from the proposed formula rate for firm CVP transmission for 
April to September 2001 is $0.70 per kWmonth, a 37-percent increase 
from the existing rate of $0.51 per kWmonth, under Rate Schedule CV-
FT3. Based on a contract agreement to provide transmission service in 
the future, the estimated rate resulting from the proposed formula rate 
for firm CVP transmission for FY 2002 is $.56 per kWmonth, a 10-percent 
increase from the existing rate of $.51 per kWmonth.
    The estimated rate resulting from the proposed formula rate for 
nonfirm CVP transmission service for April to September 2001 is 1.00 
mill/kWh. The proposed formula rate for nonfirm CVP transmission is 
based on the same two components used in the proposed formula rate for 
firm CVP transmission. A revision to the nonfirm rate resulting from 
component 1 will occur whenever component 1 of the firm transmission 
rate is revised. If the rates from the proposed formula rate are higher 
than other transmission rates in California, firm or nonfirm 
transmission service for 1 year or less may be sold at lower rates.
    The proposed formula rate for CVP transmission service is based on 
a revenue requirement that recovers: (i) The costs for facilities that 
support the transfer capability of the CVP transmission system 
(excluding generation facilities and radial lines); (ii) the 
nonfacilities costs allocated to transmission; and (iii) any 
transmission-related costs or credits incurred by Western due to 
electric industry restructuring or other changes in the industry. The 
proposed formula rate includes Western's cost for scheduling, system 
control and dispatch service, and reactive supply and voltage control 
service associated with the transmission service. The proposed formula 
rate is applicable to existing CVP firm transmission service and future 
point-to-point transmission service.

Proposed Rate for Transmission of CVP Power by Others

    Western will pass through transmission service costs or credits it 
incurs for delivering CVP power over a third party's transmission 
system to the requesting CVP customer. Rates under this schedule will 
be automatically adjusted as third party transmission costs or credits 
are adjusted.

Proposed Formula Rate for Network Integration Transmission

    If Western offers network integration transmission service, it will 
be consistent with FERC Order No. 888. The proposed formula rate is the 
product of the network customer's load ratio share times one-twelfth of 
the annual network integration transmission revenue requirement. The 
load ratio share is the network customer's hourly load coincident with 
Western's monthly CVP transmission system peak minus the coincident 
peak for all firm CVP (including reserved capacity) point-to-point 
transmission service, plus the reserved capacity of all firm point-to-
point transmission service customers.
    The proposed formula rate for network integration transmission 
service is based on a revenue requirement that recovers: (i) The costs 
for facilities that support the transfer capability of the CVP 
transmission system (excluding generation facilities and radial lines); 
(ii) the nonfacilities costs allocated to transmission; and (iii) any 
transmission-related costs or credits incurred by Western due to 
electric industry restructuring or other changes in the industry. The 
proposed formula rate includes Western's cost for scheduling, system 
control and dispatch service, and reactive supply and voltage control 
service needed to provide the transmission service.

Proposed Formula Rate for COTP Transmission

    The proposed formula rate for COTP transmission includes two 
components:

Component 1: Transmission Revenue Requirement/Western's share of COTP 
Seasonal Capacity. Component 1 is the ratio of the transmission revenue 
requirement to Western's share of COTP seasonal capacity. Western will 
update the rate resulting from component 1 at least 15 days before the 
start of each California-Oregon Intertie rating season. Seasonal 
definitions for summer, winter, and spring are June through October, 
November through March, and April through May, respectively.
Component 2: Pass through of any transmission-related costs or credits 
incurred by Western due to electric industry restructuring or other 
changes in the industry. The costs or credits in component 2, as well 
as any changes to these costs or credits, will be passed through to 
each appropriate transmission customer.
    The estimated rates resulting from the proposed formula rate for 
firm COTP transmission service for April 2001 to March 2002 are: 
Summer--$0.94 per kWmonth, winter--$1.12 per kWmonth, and spring--$1.00 
per kWmonth. These rates resulting from the proposed formula rate 
result in a 30-percent decrease during the summer, a 16-percent 
decrease during the winter, and a 25-percent decrease during the spring 
compared to the existing rate of $1.34 per kWmonth.
    The proposed formula rate for nonfirm COTP transmission is based on 
the same two components used in the proposed formula rate for firm COTP 
transmission. The estimated rates resulting from the proposed formula 
rate for nonfirm transmission service for April 2001 to March 2002 are: 
Summer--1.29 mills/kWh, winter--1.54 mills/kWh, and spring--1.37 mills/
kWh. These rates for nonfirm COTP transmission service result in an 11-
percent decrease during the summer, a 6-percent increase during the 
winter, and a 5-percent decrease during the spring compared to the 
existing rate of 1.45 mills/kWh. If the rates from the proposed formula 
rate are higher than other transmission rates in California, firm or 
nonfirm transmission service for 1 year or less may be sold at lower 
rates.
    Rates resulting from the proposed formula rate for COTP 
transmission service are based on a revenue requirement that recovers: 
(i) Western's share of costs for facilities that support

[[Page 66994]]

the transfer capability of the COTP; (ii) Western's share of the 
nonfacilities costs allocated to transmission; and (iii) any 
transmission-related costs or credits incurred by Western due to 
electric industry restructuring or other changes in the industry. The 
rates resulting from the proposed formula rate include Western's cost 
for scheduling, system control and dispatch service, and reactive 
supply and voltage control service associated with transmission 
service. The proposed formula rate would apply to existing COTP 
transmission service and future point-to-point transmission service.

Proposed Rates for Ancillary Services

    Western will provide ancillary services, subject to availability, 
at the proposed rates in Table 3. Western designed these proposed rates 
to recover only the costs it incurs for providing the service(s). If 
these cost-based rates are higher than other ancillary service rates in 
California, sales of ancillary services of 1 year or less may be sold 
at lower rates.

             Table 3.--Proposed Rates for Ancillary Services
------------------------------------------------------------------------
       Ancillary service type                        Rate
------------------------------------------------------------------------
Transmission Scheduling, System      Appropriate transmission rates
 Control and Dispatch Service--       include Western's cost.
 required to schedule movement of
 power through, out of, within, or
 into a control area.
Reactive Supply and Voltage Control  Appropriate transmission rates
 Service--reactive power support      include Western's cost.
 provided from generation
 facilities necessary to maintain
 transmission voltages within
 acceptable limits of the system.
Regulation and Frequency Response    Monthly: $2.496 per kWmonth.
 Service--provides generation to     Weekly: $0.574 per kWweek.
 match resources and loads on a      Daily: $0.082 per kWday.
 real-time continuous basis.
Energy Imbalance Service--provied    Within Limits of deviation Band:
 when a difference occurs between    Accumulated deviations are to be
 the scheduled and actual delivery    corrected or eliminated within 30
 of energy to a load or from a        days. Any net deviations that are
 generation resource within a         accumulated at the end of the
 control area over a single month.    month (positive or negative) are
                                      to be exchanged with like hours of
                                      energy or charged at the composite
                                      rate for CVP firm power then in
                                      effect.
Hourly Deviation (MW)--net           Outside Limits of Deviation Band:
 scheduled amount of energy for the  (i) Positive Deviations--the
 hour minus the hourly net metered    greater of no charge, or any
 (actual delivered) amount.           additional cost incurred.
                                     (ii) Negative Deviations--during on-
                                      peak hours, the greater of 3 times
                                      the proposed rates for CVP firm
                                      power or any additional cost
                                      incurred. During off-peak hours,
                                      the greater of the proposed rates
                                      for CVP firm power or any
                                      additional cost incurred.
Spinning Reserve Service--provides   Monthly: $2.946 per kWmonth.
 capacity available the first 10     Weekly: $0.672 per kWweek.
 minutes to take load and is         Daily: $0.096 per kWday.
 synchronized with the power system. Hourly: $0.0040 per kWh.
Supplemental Reserve Service--       Monthly: $2.491 per kWmonth.
 provides capacity not               Weekly: $0.574 per kWweek.
 synchronized, but can be available  Daily: $0.082 per kWday.
 to service loads within 10 minutes. Hourly: $0.0034 per kWh.
------------------------------------------------------------------------

    Since the proposed rates constitute a major rate adjustment as 
defined by the procedures for public participation in general rate 
adjustments, as cited below, Western will hold both a public 
information forum and a public comment forum. After reviewing public 
comments, Western will recommend provisional rates for approval on an 
interim basis by the DOE Deputy Secretary.
    These proposed rates for the CVP and COTP are established pursuant 
to the DOE Organization Act, 42 U.S.C. 7101-7352; the Reclamation Act 
of 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 that 
specifically apply to the projects involved.
    By Amendment No. 3 to Delegation Order No. 0204-108, published 
November 10, 1993 (58 FR 59716), the Secretary of Energy delegated: (1) 
The authority to develop long-term power and transmission rates on a 
nonexclusive basis to Western's Administrator; and (2) the authority to 
confirm, approve, and place into effect on a final basis, to remand, or 
to disapprove such rates to FERC. In Delegation Order No. 0204-172, 
effective November 24, 1999, the Secretary of Energy delegated the 
authority to confirm, approve, and place such rates into effect on an 
interim basis to the Deputy Secretary. Existing DOE procedures for 
public participation in power rate adjustments (10 CFR part 903) became 
effective on September 18, 1985 (50 FR 37835).

Availability of Information

    All brochures, studies, comments, letters, memoranda, or other 
documents made or kept by Western for developing the proposed rates are 
available for inspection and copying at the Sierra Nevada Regional 
Office, 114 Parkshore Drive, Folsom, California.

Regulatory Procedural 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 a proposed rulemaking. Western has 
determined that this action does not require a Regulatory Flexibility 
analysis since it is a rulemaking involving rates or services for 
public property.

Environmental Compliance

    In compliance with the National Environmental Policy Act (NEPA) of

[[Page 66995]]

1969, 42 U.S.C. 4321, et seq.; Council on Environmental Quality 
Regulations (40 CFR parts 1500-1508); and DOE NEPA Regulations (10 CFR 
part 1021), Western has determined that this action is categorically 
excluded from the preparation of an environmental assessment or an 
environmental impact statement.

Determination Under Executive Order 12866

    Western has an exemption from centralized regulatory review under 
Executive Order 12866; accordingly, no clearance of this notice by 
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 rates or services 
and involves matters of procedure.

    Dated: October 16, 2000.
Michael S. Hacskaylo,
Administrator.
[FR Doc. 00-28626 Filed 11-07-00; 8:45 am]
BILLING CODE 6450-01-P


</pre><script data-cfasync="false" src="/cdn-cgi/scripts/5c5dd728/cloudflare-static/email-decode.min.js"></script></body>
</html>