[Federal Register Volume 65, Number 43 (Friday, March 3, 2000)]
[Notices]
[Pages 11569-11574]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-5168]


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DEPARTMENT OF ENERGY

Western Area Power Administration


Proposed Rates for Central Valley and California-Oregon 
Transmission Projects

AGENCY:  Western Area Power Administration, DOE.

ACTION:  Notice of proposed rates.

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SUMMARY:  Western Area Power Administration (Western) is proposing 
rates for Central Valley Project (CVP) commercial firm power, power 
scheduling, scheduling coordinator, CVP transmission, transmission of 
CVP power by others, network transmission, California-Oregon 
Transmission Project (COTP) transmission and ancillary services. 
Current rates expire September 30, 2002. The proposed rates 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. Proposed rates are scheduled to go into effect 
on October 1, 2000, to correspond with the start of the Federal fiscal 
year (FY), and will remain in effect through December 31, 2004, which 
is the end of the current (1994) CVP Power Marketing Plan. This Federal 
Register notice initiates the formal process for the proposed rates.

DATES:  The consultation and comment period will begin today and will 
end June 2, 2000. Western will present a detailed explanation of these 
proposed rates at a public information forum on March 14, 2000, at 1 
p.m. PST, and will receive oral and written comments at a public 
comment forum on April 18, 2000, at 1 p.m., see the ADDRESSES section. 
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.

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.

SUPPLEMENTARY INFORMATION:  Proposed rates for CVP commercial firm 
power are designed to recover an annual revenue requirement that 
includes the investment repayment, interest, purchase power, 
transmission and operation and maintenance expense. A cost of service 
study allocates the projected annual revenue requirement for commercial 
firm power between capacity and energy. 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 power 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 power 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 27 percent allocated to capacity 
from October 2003 through December 2004 to 38 percent allocated to 
capacity in FY 2001. The average capacity/energy revenue requirement 
split for the rate period is 32 percent to capacity and 68 percent to 
energy.
    Western also developed proposed rates for CVP commercial firm power 
with the transmission revenue requirement removed from the commercial 
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 proposed power rates with the 
transmission revenue requirement removed are designed to recover an 
annual revenue requirement that includes investment repayment, 
interest, purchase power and operation and maintenance expense. A cost 
of service study allocates projected annual revenue requirement for 
firm power between capacity and energy. 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 power 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. 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 
power 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 21 percent

[[Page 11570]]

allocated to capacity during October 2003 through December 2004 to 30 
percent allocated to capacity in FY 2001. The average capacity/energy 
revenue requirement split for the rate period is 25 percent to capacity 
and 75 percent to energy.
    Both sets of proposed rates, i.e., the proposed rates for the CVP 
commercial firm power and the proposed rates for CVP commercial firm 
power with the transmission revenue requirement removed, include an 
Annual Energy Rate Alignment (AERA). Western will apply the AERA to 
firm energy purchased at or above an average annual load factor of 80 
percent. The AERA is set to ensure that customers would pay at least 
the equivalent of the CVP composite rate for purchases from Western. 
The billing for the AERA will occur at the end of each FY.
    Both sets of proposed rates also include a tier capacity rate. 
Western will apply the tier capacity rate to monthly capacity purchases 
at or above 90 percent of the customers' Contract Rate of Delivery 
(CRD). The tier capacity factor of 90 percent is an approximation based 
on the ratio of the sum of CVP Project Dependable Capacity, Northwest 
capacity credit and minimum monthly Pacific Gas and Electric Company 
capacity purchases to Western's system simultaneous load level.
    Proposed rates for CVP commercial firm power, the applicable 
revenue requirement split between capacity and energy, tier capacity 
rate and AERA are in Table 1.

                                                     Table 1.--Proposed Commercial Firm Power Rates
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                                                               Total
                    Effective period                         composite     Capacity  $/    Energy mills/     Capacity/     Tier capacity    AERA mills/
                                                             mills/kWh         kWmo             kWh        energy split       $/kWmo            kWh
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10/01/00 to 09/30/01....................................           15.37            3.33            9.49           38/62            5.16            5.50
10/01/01 to 09/30/02....................................           15.77            2.95           10.52           33/67            5.29            5.25
10/01/02 to 09/30/03....................................           18.65            2.98           13.33           29/71            5.42            5.00
10/01/03 to 12/31/04....................................           20.80            3.12           15.32           27/73            5.58            5.00
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    The proposed rates for CVP commercial firm power with the 
transmission revenue requirement removed, applicable revenue 
requirement split between capacity and energy, tier capacity rate and 
AERA are in Table 1A.

  Table 1A.--Proposed Commercial Firm Power Rates With the Transmission Revenue Requirement Removed From the Commercial Firm Power Revenue Requirement
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                                                               Total
                    Effective period                         composite      Capacity $/    Energy mills/     Capacity/     Tier capacity  AERA mills/kWh
                                                             mills/kWh         kWmo             kWh        energy split       $/kWmo
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10/01/00 to 09/30/01....................................           13.55            2.23            9.49           30/70            5.16            5.50
10/01/01 to 09/30/02....................................           14.22            2.00           10.52           26/74            5.29            5.25
10/01/02 to 09/30/03....................................           17.12            2.05           13.33           22/78            5.42            5.00
10/01/03 to 12/31/04....................................           19.20            2.14           15.32           21/79            5.58            5.00
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    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). The Federal Energy Regulatory Commission (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, the AERA energy rate is 4.09 mills/kWh and the 
capacity rate is $3.81 per kilowattmonth (kWmo). The proposed rates for 
CVP commercial firm power will result in an overall composite rate 
decrease of approximately 17 percent on October 1, 2000, 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\1\
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                                                    Percentage change in commercial firm power rates
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                                                     Total                      Base
                Effective period                   composite     Percent    capacity $/    Percent    Base energy    Percent    AERA mills/    Percent
                                                      rate        change        kWmo        change     mills/ kWh     change        kWh         change
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                                                                  Current Rate Schedule
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Existing 10/01/00 to 09/30/01...................        18.56  ...........         3.81  ...........        10.51  ...........         4.09  ...........
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                                                                     Proposed Rates
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10/01/00 to 09/30/01............................        15.37          -17         3.33          -13         9.49          -10         5.50           34
10/01/01 to.....................................        15.77          -15         2.95          -23        10.52  ...........         5.25           28
10/01/02 to 09/30/03............................        18.65  ...........         2.98          -22       -13.33           27         5.00           22
0/01/03 to 12/31/04.............................        20.80           12         3.12          -18        15.32           46         5.00          22
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\1\ The percent changes do not include the impacts of the tier capacity rates.


[[Page 11571]]

    The proposed rates for CVP commercial firm power with the 
transmission revenue requirement removed will result in an overall 
composite rate decrease of approximately 27 percent on October 1, 2000, 
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 along with the 
percentage change in the rates.

                        Table 2A.--Comparison of Current and Proposed Rates With the Transmission Revenue Requirement Removed \2\
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                                                    Percentage change in commercial firm power rates
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                                                     Total
                Effective period                   composite     Percent    Capacity  $/   Percent    Base energy    Percent    AERA mills/    Percent
                                                      rate        change        kWmo        change     mills/ kWh     change        kWh         change
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                                                                  Current Rate Schedule
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Existing 10/01/00 to 09/30/01...................        18.56  ...........         3.81  ...........        10.51  ...........         4.09  ...........
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                                            Proposed Rates with the transmission revenue requirement removed
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10/01/00 to 09/30/01............................        13.55          -27         2.23          -41         9.49          -10         5.50           34
10/01/01 to 09/30/02............................        14.22          -23         2.00          -48        10.52  ...........         5.25           28
10/01/02 to 09/30/03............................        17.12           -8         2.05          -46        13.33           27         5.00           22
10/01/03 to 12/31/04............................        19.20            3         2.14          -44        15.32           46         5.00          22
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\2\ The percent changes do not include the impacts of the tier capacity rates. 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 
Commercial Firm Power

Power Factor Adjustment

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

Low Voltage Loss Adjustment

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

Proposed Rate for Power Scheduling Service

    The proposed rate for power scheduling service is $84.38 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 $75.54 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.

Proposed Formula Rate for CVP Transmission

    The proposed formula rate for firm CVP transmission includes two 
components.
[GRAPHIC] [TIFF OMITTED] TN03MR00.008

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 (CVP capacity) and the total transmission capacity under long-
term contract 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 
incurred by Western due to electric industry restructuring or other 
changes in the industry. The costs in Component 2, as well as any 
changes to these costs, will be directly passed through to each 
appropriate transmission customer.
    Western will revise the rate resulting from Component 1 of the 
proposed formula rate based on: (i) Updated data as of April 30 of each 
year; and (ii) a change in the numerator or denominator that results in 
a rate change of at least $.05 per kWmo. The rate resulting from the 
proposed formula rate for firm CVP transmission for FY 2001 is $0.73 
per kWmo, a 43-percent increase from the existing rate of $0.51 per 
kWmo, under Rate Schedule CV-FT3. Based on a contract agreement to 
provide transmission service in the future, the

[[Page 11572]]

rate resulting from the proposed formula rate for firm CVP transmission 
for FY 2002 is $.58 per kWmo, a 14-percent increase from the existing 
rate of $.51 per kWmo.
    The rate resulting from the proposed formula rate for nonfirm CVP 
transmission service for FY 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. Firm or 
nonfirm transmission service for 1 year or less may be at rates lower 
than the rates resulting from the proposed formula rate if these cost-
based rates are higher than the current rate for transmission sales.
    The proposed formula rate for CVP transmission service is based on 
a revenue requirement that recovers: (i) The CVP transmission system 
costs for facilities associated with providing all transmission 
service; (ii) the nonfacilities costs allocated to transmission 
service; and (iii) any transmission-related costs 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 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 directly pass through transmission service costs it 
incurs for delivering CVP power over a third party's transmission 
system to the requesting CVP customer. Rates under this schedule are 
proposed to be automatically adjusted as third party transmission costs 
are adjusted.

Proposed Formula Rate for Network Transmission

    If Western offers network transmission service, its proposed 
formula rate is the product of the network customer's load ratio share 
times one-twelfth of the annual network 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. The proposed formula rate for 
network transmission service is based on a revenue requirement that 
recovers: (i) CVP transmission system costs for facilities associated 
with providing all transmission service; (ii) the nonfacilities costs 
allocated to transmission service; and (iii) any transmission-related 
costs 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 needed to provide the transmission 
service.

Proposed Formula Rate for COTP Transmission

    The proposed formula rate for COTP transmission includes two 
components.
[GRAPHIC] [TIFF OMITTED] TN03MR00.009

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 (COI) 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 
incurred by Western due to electric industry restructuring or other 
changes in the industry. The costs in Component 2, as well as any 
changes to these costs, will be directly passed through to each 
appropriate transmission customer.
    The rates resulting from the proposed formula rate for firm COTP 
transmission service for FY 2001 are: summer--$1.47 per kWmo, winter--
$1.66 per kWmo and spring--$1.53 per kWmo. These rates resulting from 
the proposed formula rate result in a 10-percent increase during the 
summer, a 24-percent increase during the winter and a 14-percent 
increase during the spring compared to the existing rate of $1.34 per 
kWmo.
    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. Rates resulting from the proposed formula rate for 
nonfirm transmission service for FY 2001 are: summer--2.01 mills/kWh, 
winter--2.28 mills/kWh and spring--2.10 mills/kWh. These rates for 
nonfirm COTP transmission service result in a 39-percent increase 
during the summer, a 57-percent increase during the winter and a 45-
percent increase during the spring compared to the existing rate of 
1.45 mills/kWh. Firm or nonfirm transmission service for 1 year or less 
may be at rates lower than the rates resulting from the proposed 
formula rate if these cost-based rates are higher than the current rate 
for transmission sales.
    Rates resulting from the proposed formula rate for COTP 
transmission service are based on a revenue requirement that recovers: 
(i) Western's share of COTP transmission system costs for facilities 
associated with providing all transmission service; (ii) Western's 
share of the nonfacilities costs allocated to transmission service; and 
(iii) any transmission-related costs 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 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). Sales 
of ancillary services of 1 year or less may be at rates lower than the 
proposed rates if these cost-based rates are higher than the current 
rate for ancillary service sales.

[[Page 11573]]



             Table 3.--Proposed Rates for Ancillary Services
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         Ancillary service type                        Rate
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Transmission Scheduling, System Control  Appropriate transmission rates
 and Dispatch Service--required to        include Western's cost.
 schedule movement of power through,
 out of, within, or into a control area.
Reactive Supply and Voltage Control--    Appropriate transmission rates
 reactive power support provided from     include Western's cost.
 generation facilities necessary to
 maintain transmission voltages within
 acceptable limits of the system.
Regulation and Frequency Response        Monthly: $1.78 per kWmonth.
 Service--provides generation to match   Weekly: $0.42 per kWweek.
 resources and loads on a real-time      Daily: $0.06 per kWday.
 continuous basis.
Energy Imbalance Service--provided when  Within Limits of Deviation
 a difference occurs between the          Band: Accumulated deviations
 scheduled and actual delivery of         are to be corrected or
 energy to a load or from a generation    eliminated within 30 days. Any
 resource within a control area over a    net deviations that are
 single month.                            accumulated at the end of the
                                          month (positive or negative)
                                          are to be exchanged with like
                                          hours of energy or charged at
                                          the composite rate for CVP
                                          commercial firm power then in
                                          effect.
Hourly Deviation (MW)--net scheduled     Outside Limits of Deviation
 amount of energy for the hour minus      Band:
 the hourly net metered (actual          (i) Positive Deviations--The
 delivered) amount.                       greater of no charge, or any
                                          additional cost incurred.
                                         (ii) Negative Deviations--
                                          during on-peak hours, the
                                          greater of 3 times the
                                          proposed rates for CVP
                                          commercial firm power or any
                                          additional cost incurred.
                                          During off-peak hours, the
                                          greater of the proposed rates
                                          for CVP commercial firm power
                                          or any additional cost
                                          incurred.
Spinning Reserve Service--provides       Monthly: $1.95 per kWmonth.
 capacity available the first 10         Weekly: $0.42 per kWweek.
 minutes to take load and is             Daily: $0.06 per kWday.
 synchronized with the power system.     Hourly: $0.0027 per kWh.
Supplemental Reserve Service--provides   Monthly: $1.77 per kWmonth.
 capacity not synchronized, but can be   Weekly: $0.42 per kWweek.
 available to serve loads within 10      Daily: $0.06 per kWday.
 minutes.                                Hourly: $0.0024 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 the Deputy Secretary of DOE approve 
the proposed rates (and as amended) on an interim basis.

Legal Authority

    These proposed rates for CVP and COTP power, transmission and 
power-related services are being 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, located at 114 Parkshore Drive, Folsom, California 95630-4710.

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

Environmental Compliance

    In compliance with the National Environmental Policy Act (NEPA) of 
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 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 rates or services 
and involves matters of procedure.


[[Page 11574]]


    Dated: February 18, 2000.
Michael S. Hacskaylo,
Administrator.
[FR Doc. 00-5168 Filed 3-2-00; 8:45 am]
BILLING CODE 6450-01-P