[Federal Register Volume 59, Number 25 (Monday, February 7, 1994)]
[Unknown Section]
[Page 0]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 94-2730]


[[Page Unknown]]

[Federal Register: February 7, 1994]


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DEPARTMENT OF ENERGY
Western Area Power Administration

 

Parker-Davis Project Notice of Rate Order No. WAPA-55

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of Rate Order--Parker-Davis Project (P-DP) Firm Power 
Rate and Firm and Nonfirm Transmission Service Rate Adjustments.

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

SUMMARY: Notice is given of the confirmation and approval by the Deputy 
Secretary of the Department of Energy (DOE) of Rate Order No. WAPA-55 
placing the proposed rate schedules--firm power PD-F4, firm 
transmission service PD-FT4, nonfirm transmission service PD-NFT4, and 
firm transmission service for Salt Lake City Area/Integrated Projects 
(SLCA/IP) PD-FCT4--for the P-DP of the Western Area Power 
Administration (Western) into effect on an interim basis. These 
proposed P-DP rates, hereafter called the provisional P-DP rates, will 
remain in effect on an interim basis until the Federal Energy 
Regulatory Commission (FERC) confirms, approves, and places them into 
effect on a final basis for a 5-year period or until superseded.
    The Deputy Secretary, DOE, approved the existing P-DP rate 
schedules PD-F3, PD-FCT3, and PF-NFT3 by Rate Order No. WAPA-48 on an 
interim basis, effective on October 1, 1990 (55 FR 36887, September 7, 
1990). FERC approved the P-DP rate schedules on a final basis through 
September 30, 1992, by Order dated November 15, 1990 (53 FERC Par. 
62,157).
    The Assistant Secretary for Conservation and Renewable Energy on 
August 19, 1992 by Rate Order No. WAPA-57, extended these rate 
schedules for not more than one year (57 FR 39400, August 31, 1992). 
The Acting Assistant Secretary for Energy Efficiency and Renewable 
Energy on September 29, 1993, by Rate Order No. WAPA-64, further 
extended these rate schedules through March 31, 1994 (58 FR 50917; 
September 29, 1993).
    Neither of said WAPA Rate Orders, 57 or 64 were submitted to FERC 
for its concurrence, inasmuch as these orders were in the nature of 
temporary extensions of existing rates, pending the development of long 
term rates, so that FERC approval would have been premature. In any 
event, rates of such nature need not be approved by FERC, as specified 
in existing regulations, 10 CFR 902.23(b).
    Western is proposing to implement a two-step process for the 
provisional P-DP rates for firm power and firm and nonfirm transmission 
service. Step one of the provisional P-DP rates will become effective 
February 1, 1994, and step two of the provisional P-DP rates will 
become effective October 1, 1995.
    Step one of the provisional P-DP rates consists of an energy rate 
of 5.79 mills per kilowatthour (mills/kWh) and a capacity rate of $2.54 
per kilowatt/month (kW/month) for a composite rate of 11.58 mills/kWh. 
Step one of the provisional P-DP rates for transmission service 
consists of a firm transmission service rate of $10.40 per kilowatt/
year (kW/year), a nonfirm transmission service rate of 1.98 mills/kWh, 
and a firm transmission service rate for SLCA/IP of $5.20/kW/season. A 
season for the firm transmission service rate for SLCA/IP is 6 months.
    Step two of the provisional P-DP rates consists of an energy rate 
of 6.01 mills/kWh and a capacity rate of $2.63/kW/month for a composite 
rate of 12.01 mills/kWh. Step two of the provisional P-DP rates for 
transmission service consists of a firm transmission service rate of 
$12.55/kW/year, a nonfirm transmission service rate of 2.39 mills/kWh, 
and a firm transmission service rate for SLCA/IP of $6.27/kW/season.
    A comparison of existing P-DP rates and the two-step provisional P-
DP rates follows:

  Comparison of Existing P-DP Rates and Step One Provisional P-DP Rates 
------------------------------------------------------------------------
                                               Provisional              
                             Existing rates       rates        Percent  
                                 FY 1990     effective 2/1/   change (%)
                                                  1994*                 
------------------------------------------------------------------------
Power Rate Schedule........           PD-F3           PD-F4  ...........
Composite (mills/kWh)......            9.03           11.58           28
Energy (mills/kWh).........            4.52            5.79           28
Capacity ($/kW/month)......            1.98            2.54           28
Firm Transmission Service                                               
 Rate Schedule.............          PD-FT3          PD-FT4  ...........
Firm Transmission Service                                               
 ($/kW/year)...............            8.20           10.40           27
Nonfirm Transmission                                                    
 Service Rate Schedule.....         PD-NFT3         PD-NFT4  ...........
Nonfirm Transmission                                                    
 Service (mills/kWh).......            1.50            1.98           32
Firm Transmission Service                                               
 for SLCA/IP Rate Schedule.         PD-FCT3         PD-FCT4  ...........
Firm Transmission Service                                               
 for SLCA/IP ($/kW/season).            4.10            5.20           27
------------------------------------------------------------------------
*The first steps of the provisional P-DP rates are in effect from       
  February 1, 1994, through September 30, 1995.                         


  Comparison of Existing P-DP Rates and Step Two Provisional P-DP Rates 
------------------------------------------------------------------------
                                               Provisional              
                             Existing rates       rates        Percent  
                                FY 1990      effective 10/1/  change (%)
                                                 1995*                  
------------------------------------------------------------------------
Power Rate Schedule........           PD-F3           PD-F4  ...........
Composite (mills/kWh)......            9.03           12.01           33
Energy (mills/kWh).........            4.52            6.01           33
Capacity ($/kW/month)......            1.98            2.63           33
Firm Transmission Service                                               
 Rate Schedule.............          PD-FT3          PD-FT4  ...........
Firm Transmission Service                                               
 ($/kW/year)...............            8.20           12.55           53
Nonfirm Transmission                                                    
 Service Rate Schedule.....         PD-NFT3         PD-NFT4  ...........
Nonfirm Transmission                                                    
 Service (mills/kWh).......            1.50            2.39           59
Firm Transmission Service                                               
 For SLCA/IP Rate Schedule.         PD-FCT3         PD-FCT4  ...........
Firm Transmission Service                                               
 for SLCA/IP ($/kW/season).            4.10            6.27           53
------------------------------------------------------------------------
*The second steps of the provisional P-DP rates are in effect from      
  October 1, 1995, through January 31, 1999, or until superseded.       

DATES: The P-DP Rate Schedules PD-F4, PD-FT4, PD-NF4, and PD-FCT4 will 
become effective on an interim basis beginning February 1, 1994, and 
will be in effect until FERC confirms, approves, and places the rate 
schedules into effect on a final basis for a 5-year period or until 
superseded.

FOR FURTHER INFORMATION CONTACT:

Mr. Thomas A. Hine, Area Manager, Phoenix Area Office, Western Area 
Power Administration, P.O. Box 6457, Phoenix, AZ 85005-6457, (602) 352-
2453
Ms. Deborah M. Linke, Director, Division of Marketing and Rates, 
Western Area Power Administration, P.O. Box 3402, Golden, CO 80401-
3398, (303) 231-1545
Mr. Joel Bladow, Assistant Administrator for Washington Liaison, 
Western Area Power Administration, Room 8G-061, Forrestal Building, 
1000 Independence Avenue SW., Washington, DC 20585-0001, (202) 586-5581

SUPPLEMENTARY INFORMATION: 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 the Administrator of 
Western; (2) the authority to confirm, approve, and place such rates 
into effect on an interim basis to the Deputy Secretary; and (3) the 
authority to confirm, approve, and place into effect on a final basis, 
to remand, or to disapprove such rates to FERC. Existing DOE procedures 
for public participation in power rate adjustments (10 CFR Part 903) 
became effective on September 18, 1985 (50 FR 37837).
    These power and transmission rates are established pursuant to the 
DOE Organization Act (42 U.S.C. Sec. 7101 et seq.); the Reclamation Act 
of 1902 (43 U.S.C. Sec. 371 et seq.) as amended and supplemented by 
subsequent enactments, particularly section 9(c) of the Reclamation 
Project Act of 1939 (43 U.S.C. Sec. 485h(c)); section 2 of the Rivers 
and Harbors Act of 1935 (49 Stat. 1028, 1039); the Parker-Davis Act of 
1954 (68 Stat. 143); Final Rule (10 CFR Part 904) published in the 
Federal Register at 51 FR 43154 on November 28, 1986; the DOE financial 
reporting policies, procedures, and methodology (DOE RA 6120.2 dated 
September 20, 1979); and the procedures for public participation in 
rate adjustments for power and transmission service marketed by Western 
(10 CFR Part 903) published in the Federal Register at 50 FR 37837 on 
September 18, 1985.
    Based upon data available in fiscal year (FY) 1991, the PRS for the 
P-DP showed that the existing composite rate of 9.03 mills/kWh for firm 
power, firm transmission rate of $8.20/kW/year, nonfirm transmission 
rate of 1.50 mills/kWh, and a firm transmission service rate for SLCA/
IP of $4.10/kW/season would not provide sufficient revenues to pay the 
project costs within the prescribed time periods. The Ratesetting PRS 
indicates substantial rate increases for firm power and firm and 
nonfirm transmission service are required in order to meet revenue 
requirements for FY 1994 through the end of the study. Because this 
represents a substantial increase over the existing P-DP rates, Western 
is proposing to implement a two-step rate process for firm power and 
firm and nonfirm transmission service.
    Rate increases are due largely to the increases in replacement and 
addition activities on P-DP. The original P-DP investment was fully 
paid in 1984 and the irrigation investment was fully paid in 1986.
    However, the P-DP is undergoing a major replacement and 
refurbishment plan needed for environmental compliance, safety, and 
reliability. The rate increases can also be attributed to an increase 
in purchased power expense. The increase in purchased power expense 
resulted from flooding conditions along the Colorado River in 
southwestern Arizona which created a generation deficiency.
    During the 143-day comment period, Western received 31 written 
comments. In addition, nine speakers commented during the September 11, 
1992, public comment forum. During the second comment period of 70 
days, Western received 19 written comments. In addition, seven speakers 
commented during the July 14, 1993, public comment forum. All comments 
and responses are addressed in the rate order.
    Rate Order No. WAPA-55, confirming, approving, and placing the P-DP 
proposed rate adjustments into effect on an interim basis is issued, 
and the rate schedules PD-F4, PD-FT4, PD-NFT4, and PD-FCT4 will be 
promptly submitted to FERC for confirmation and approval on a final 
basis.

    Issued in Washington, D.C., January 6, 1994.
William H. White,
Deputy Secretary.

Department of Energy

Deputy Secretary

    In the matter of: Western Area Power Administration, Rate 
Adjustments for Phoenix Area Office, Parker-Davis Project.
    [Rate Order No. WAPA-55] order confirming, approving, and 
placing the Parker-Davis Project; rates for firm power and firm and 
nonfirm transmission service into effect on an interim basis.
January 6, 1994.
    Pursuant to section 302(a) of the Department of Energy (DOE) 
Organization Act, 42 U.S.C. Sec. 7152(a) et seq., the power marketing 
functions of the Secretary of the Interior and the Bureau of 
Reclamation (Reclamation) under the Reclamation Act of 1902, 43 U.S.C. 
Sec. 371 et seq., as amended and supplemented by subsequent enactments, 
particularly section 9(c) of the Reclamation Project Act of 1939, 43 
U.S.C. Sec. 485h(c), and other acts specifically applicable to the 
projects involved, were transferred to and vested in the Secretary of 
Energy (Secretary).
    By Amendment No. 3 to Delegation Order No. 0204-108, published on 
November 10, 1993 (58 FR 59716), the Secretary delegated: (1) The 
authority to develop long-term power and transmission rates on a 
nonexclusive basis to the Administrator of the Western Area Power 
Administration (Western); (2) the authority to confirm, approve, and 
place such rates into effect on an interim basis to the Deputy 
Secretary; and (3) the authority to confirm, approve, and place into 
effect on a final basis, to remand, or to disapprove such rates to the 
Federal Energy Regulatory Commission (FERC). Existing DOE procedures 
for public participation in power rate adjustments (10 CFR Part 903) 
became effective on September 18, 1985 (50 FR 37835).

Acronyms and Definitions

    As used in this rate order, the following acronyms and definitions 
apply:

    AC Intertie: Pacific Northwest/Pacific Southwest Intertie 
Project.
    Additions: A unit of property constructed or acquired which 
enhances or improves a project or system and which is properly 
allocated to power or the joint features allocated to power.
    Apportionment of Cost Study: A study that apportions costs to 
users in proportion to benefits received from the respective P-DP 
power and transmission system.
    Composite Rate: Combination of an energy and a capacity 
component.
    Cost Evaluation Period (CEP): The first 5 future years in the 
PRS. Normally consistent with the budget period.
    CRSP: Colorado River Storage Project.
    CSRS: Civil Service Retirement System.
    Current PRS: The PRS included in this rate, which was used to 
test adequacy of the P-DP existing rates.
    Customer Brochure: A document prepared for public distribution 
explaining the background of the rate proposal contained in this 
rate order.
    Deputy Secretary: The approval authority to confirm, approve, 
and place rates into effect on an interim basis.
    DOE: Department of Energy.
    DOE Act: Department of Energy Organization Act, August 4, 1977 
(42 U.S.C. 7101 et seq.).
    DOE Order No. RA 6120.2: An order dealing with power marketing 
administration financial reporting.
    EIS: Environmental impact statement.
    Energy Rate: Expressed in mills per kWh. Applied to each kWh 
made available to each contractor.
    Engineering Ten-Year Construction and Replacement Plan: A 
planning document prepared by Western for transmission system 
construction for a 10-year period. Also referred to as the 
``Engineering Ten-Year Plan.''
    FERC: Federal Energy Regulatory Commission.
    FDR: Facilities development report. A planning document prepared 
by Western for specific transmission system construction.
    FY: Fiscal year.
    IDC: Interest during construction.
    Interior: U.S. Department of the Interior.
    kW: Kilowatt.
    kW/month: The greater of (1) the highest 30-minute demand 
measured during the month, not to exceed the contract obligation, or 
(2) the contract rate of delivery (kilowatt per month).
    $/kW/month: Monthly charge for capacity (usage--$ per kilowatt 
per month).
    $/kW/season: 6-month charge for capacity (usage--$ per kilowatt 
per season).
    kWh: Kilowatthour.
    MAF: Million acre-feet.
    mills/kWh: Mills per kilowatthour.
    Multiproject Costs: These are costs for facilities being charged 
to one project that benefit other projects.
    MW: Megawatt.
    MWD: Metropolitan Water District of Southern California.
    NEPA: National Environmental Policy Act of 1969 (42 U.S.C. 4321 
et seq.).
    O&M: Operation and maintenance.
    P-DP: Parker-Davis Project.
    PAO: Phoenix Area Office.
    Pinch-point: The FY in which the level of the rate is set as 
dictated by a revenue requirement in some future year to meet 
relatively large annual costs or to repay investments which come 
due.
    PRS: Power repayment study.
    Proposed Rate: A rate revision that the Administrator of Western 
recommends to the Deputy Secretary for approval.
    Provisional Rate: A rate which has been confirmed, approved, and 
placed into effect on an interim basis by the Deputy Secretary.
    Ratesetting PRS: The PRS that utilizes, in whole or part, 
proposed or assigned rates. It is designed to demonstrate that 
potential revenue levels will satisfy the cost recovery criteria 
over the remainder of the power system's repayment period.
    Reclamation: Bureau of Reclamation, U.S. Department of the 
Interior.
    Replacements: A unit of property constructed or acquired as a 
substitute for an existing unit of property for the purpose of 
maintaining the power features of a project or the joint features 
properly allocated to power.
    Replacement Study: The cyclical analysis of replacement service 
lives. A high level of replacement activity for a few consecutive 
years will reoccur in future years at a similar high level with the 
years in between tending to be at a lesser level of replacement.
    Secretary: Secretary of Energy.
    SLCA: Salt Lake City Area.
    SLCA/IP: The Salt Lake City Area Integrated Projects, which 
encompass the combined sales and resources of the CRSP, Collbran, 
and Rio Grande Projects.
    Treasury: Secretary of the Department of the Treasury.
    Upper Basin: That part of the Colorado River Basin consisting of 
the southwestern part of Wyoming, western Colorado, most of New 
Mexico, Utah, and the northwestern section of Arizona.
    Western: Western Area Power Administration, DOE.

Effective Date

    Western is proposing to implement a two-step rate process for firm 
power and firm and nonfirm transmission service. Step one of the P-DP 
provisional rates for firm power and firm and nonfirm transmission 
service will become effective on an interim basis beginning February 1, 
1994. Step two of the provisional P-DP rates will become effective 
October 1, 1995, through January 31, 1999. The P-DP provisional rates 
will be in effect until FERC confirms, approves, and places the rate 
schedules into effect on a final basis for a 5-year period, or until 
superseded.

Public Notice and Comment

    The procedures for public participation in power and transmission 
rate adjustments and extensions, 10 CFR Part 903, have been followed by 
Western in the development of the P-DP firm power and firm and nonfirm 
transmission rates. The provisional P-DP rates for firm power and firm 
and nonfirm transmission service represent an increase of more than 1 
percent in total P-DP revenues; therefore, it is a major rate 
adjustment as defined at 10 CFR Secs. 903.2(e) and 903.2(f)(1). The 
distinction between a minor and major rate adjustment is used only to 
determine the public procedures for the rate adjustment.
    The following summarizes the steps Western took to ensure 
involvement of interested parties in the rate process:
    1. A Federal Register notice was published on May 8, 1992 (57 FR 
19904), officially announcing the proposed P-DP rate adjustments for 
firm power and firm and nonfirm transmission service; initiating the 
public consultation and comment period; announcing the June 19, 1992, 
public information forum and the June 30, 1992, public information and 
comment forum; and presenting procedures for public participation.
    2. A letter was mailed to all P-DP customers and other interested 
parties on May 19, 1992, providing a copy of the P-DP proposed rate 
adjustments brochure and announcing the informal customer meeting. The 
informal customer meeting was held on June 3, 1992, in Phoenix, 
Arizona. At this informal meeting, Western representatives explained 
the need for the increase and answered questions from those attending.
    3. At the public information forum held on June 19, 1992, Western 
explained the need for the proposed rate adjustments and answered 
questions from those attending. Western also announced a second public 
comment forum and the extension of the consultation and comment period 
for the P-DP.
    4. At the public information forum and public comment forum held on 
June 30, 1992, Western explained the need for the proposed P-DP rate 
adjustments in greater detail and answered questions.
    5. On August 6, 1992, a Federal Register notice was published (57 
FR 34776) formally announcing the extension of the consultation and 
comment period through September 28, 1992, for the proposed rate 
adjustments for the P-DP.
    6. An additional public comment forum was held on September 11, 
1992, to give the public an opportunity to comment on the proposed P-DP 
rates for the record. Nine people, who represent customers and customer 
groups, made oral comments.
    7. Thirty-one written comment letters were received during the 143-
day consultation and comment period. The consultation and comment 
period ended September 28, 1992.
    8. A letter was mailed to all P-DP customers and other interested 
parties on June 29, 1993, announcing the reopening of the consultation 
and comment period and providing a copy of an addendum to the P-DP 
proposed rate adjustments brochure. This letter also announced the 
public information/public comment forum to be held on July 14, 1993, in 
Phoenix, Arizona.
    9. On July 13, 1993, a Federal Register notice was published (58 FR 
37731) formally announcing the reopening of the consultation and 
comment period on the proposed P-DP firm power and firm and nonfirm 
transmission service rate adjustments.
    10. At the public information forum held on July 14, 1993, Western 
representatives explained the need to reopen the consultation and 
comment period and answered questions. The consultation and comment 
period was reopened due to an unexpected increase in purchased power in 
FY 1993.
    11. The public comment forum was held on July 14, 1993, to give the 
public another opportunity to comment on the proposed P-DP rates for 
the record. Seven people, who represent customers and customer groups, 
made oral comments.
    12. Nineteen written comment letters were received during the 
second consultation and comment period of 70 days. The second 
consultation and comment period ended on September 7, 1993.

Project History

    The Parker Dam Power Project was authorized by section 2 of the 
Rivers and Harbors Act of August 30, 1935 (49 Stat. 1028, 1039), and 
the Davis Dam Project was authorized April 26, 1941, by the Acting 
Secretary of the Interior under Provisions of the Reclamation Project 
Act of 1939 (43 U.S.C. Sec. 485 et seq.). The P-DP was formed by the 
consolidation of the two projects under the terms of the Act of May 28, 
1954 (68 Stat. 143).
    Davis Dam, which creates Lake Mohave, provides regulation, both 
hourly and seasonally, of the water releases from Lake Mead (through 
Hoover Dam and Powerplant) to facilitate water delivery for downstream 
irrigation requirements and for water delivery beyond the boundary of 
the United States as required by the Mexican Water Treaty. Operation of 
the powerplant began in January 1951 with a generating capacity of 
225,000 kW. During the period 1974-78 the generator nameplate capacity 
was increased to 240,000 kW by rewinding the generator stators.
    Construction of Parker Dam was authorized for the purposes of 
controlling floods, improving river navigation, regulating the flow of 
the Colorado River, providing for storage and for the delivery of the 
stored waters thereof, for the reclamation of public lands and Indian 
reservations and for other beneficial uses, and for the generation of 
electric energy as a means of making the P-DP a self-supporting and 
financially solvent undertaking.
    Parker Dam was constructed by Reclamation with funds advanced by 
MWD. Lake Havasu, the reservoir created behind Parker Dam, serves as 
the forebay from which water is diverted into the MWD aqueduct. The 
aqueduct delivers a major portion of California's entitlement of 
Colorado River water to southern California and is the diversion point 
for delivering Central Arizona Project water to Arizona. The reservoir 
operation is limited to minor storage fluctuations. The dam provides a 
head of approximately 75 feet for the Parker Powerplant. Reclamation 
began operation of the Parker Powerplant in December 1942. Although the 
total generator nameplate capacity is 120,000 kW, the powerplant 
capacity is essentially limited to 104,000 kW because of operating 
constraints of downstream physical structures, primarily Headgate Rock 
Dam. Under contract, MWD is entitled to one-half of the net energy 
generated by the Parker Powerplant at any given time.
    All facilities of the P-DP were operated and maintained by 
Reclamation until the formation of DOE pursuant to the DOE Act, enacted 
by Congress on August 4, 1977. Pursuant to section 302 of the DOE Act 
(42 U.S.C. Sec. 7152), responsibility for the power marketing functions 
of Reclamation, including the construction, operation, and maintenance 
of substations, transmission lines, and attendant facilities, was 
transferred to Western. The responsibility for operation and 
maintenance of the dams and powerplants remains with Reclamation.

Power Repayment Studies

    PRSs are prepared each FY to determine if power revenues will be 
sufficient to pay, within the prescribed time periods, all costs 
assigned to the power function. Repayment criteria are based on law, 
policies, and authorizing legislation. DOE Order No. RA 6120.2, section 
12.b, states:


    In addition to the recovery of the above costs (operation and 
maintenance and interest expenses) on a year-by-year basis, the 
expected revenues are at least sufficient to recover (1) each dollar 
of power investment at Federal hydroelectric generating plants 
within 50 years after they become revenue producing, except as 
otherwise provided by law; plus, (2) each annual increment of 
Federal transmission investment within the average service life of 
such transmission facilities or within a maximum of 50 years, 
whichever is less; plus, (3) the cost of each replacement of a unit 
of property of a Federal power system within its expected service 
life up to a maximum of 50 years; plus, (4) each dollar of assisted 
irrigation investment within the period established for the 
irrigation water users to repay their share of construction costs; 
plus (5) other costs such as payments to basin funds, participating 
projects, or States.

Existing and Provisional P-DP Rates

    A comparison of existing P-DP rates and two-step provisional P-DP 
rates follows: 

  Comparison of Existing P-DP Rates and Step One Provisional P-DP Rates 
------------------------------------------------------------------------
                                               Provisional              
      Type of Service        Existing rates    rates 2/1/      Percent  
                                10/1/1990         1994*       change (%)
------------------------------------------------------------------------
Power Rate Schedule........           PD-F3           PD-F4  ...........
Composite (mills/kWh)......            9.03           11.58           28
Energy (mills/kWh).........            4.52            5.79           28
Capacity ($/kW/month)......            1.98            2.54           28
Firm Transmission Rate                                                  
 Service Schedule..........          PD-FT3          PD-FT4  ...........
Firm Transmission Service                                               
 ($/kW/year)...............            8.20           10.40           27
Nonfirm Transmission                                                    
 Service Rate Schedule.....         PD-NFT3         PD-NFT4  ...........
Nonfirm Transmission                                                    
 Service (mills/kWh).......            1.50            1.98           32
Firm Transmission Service                                               
 For SLCA/IP Rate Schedule.         PD-FCT3         PD-FCT4  ...........
Firm Transmission Service                                               
 for SLCA/IP ($/kW/season).            4.10            5.20           27
------------------------------------------------------------------------
*The first steps of the provisional P-DP rates are in effect from       
  February 1, 1994, through September 30, 1995.                         


  Comparison of Existing P-DP Rates and Step Two Provisional P-DP Rates 
------------------------------------------------------------------------
                                               Provisional              
      Type of service        Existing rates    rates 10/1/     Percent  
                                10/1/1990         1995*       change (%)
------------------------------------------------------------------------
Power Rate Schedule........           PD-F3           PD-F4  ...........
Composite (mills/kWh)......            9.03           12.01           33
Energy (mills/kWh).........            4.52            6.01           33
Capacity ($/kW/month)......            1.98            2.63           33
Firm Transmission Service                                               
 Rate Schedule.............          PD-FT3          PD-FT4  ...........
Firm Transmission Service                                               
 ($/kW/year)...............            8.20           12.55           53
Nonfirm Transmission                                                    
 Service Rate Schedule.....         PD-NFT3         PD-NFT4  ...........
Nonfirm Transmission                                                    
 Service (mills/kWh).......            1.50            2.39           59
Firm Transmission Service                                               
 For SLCA/IP Rate Schedule.         PD-FCT3         PD-FCT4  ...........
Firm Transmission Service                                               
 for SLCA/IP ($/kW/season).            4.10            6.27           53
------------------------------------------------------------------------
*The second steps of the provisional P-DP rates are in effect from      
  October 1, 1995, through January 31, 1999, or until superseded.       

Certification of Rates

    Western's Administrator has certified that the P-DP firm power and 
firm and nonfirm transmission service rates placed into effect on an 
interim basis herein are the lowest possible consistent with sound 
business principles. The rates have been developed in accordance with 
administrative policies and applicable laws.

Discussion

    Based upon FY 1991 data, the PRS for the P-DP showed that the 
existing composite rate of 9.03 mills/kWh for firm power, a 
transmission rate of $8.20/kW/year, a nonfirm transmission service rate 
of 1.50 mills/kWh, and a firm transmission service rate for SLCA/IP of 
$4.10/kW/season would not provide sufficient revenues to pay the 
project costs within the prescribed time periods. The Ratesetting PRS 
indicates that a substantial rate adjustment for firm power and firm 
and nonfirm transmission service is required to meet revenue 
requirements for FY 1994 through the end of the study. Because the firm 
transmission service rate adjustments are substantial increases over 
the existing P-DP rates, and in response to customer requests and 
comments, Western is proposing to implement a two-step rate process for 
firm power and firm and nonfirm transmission service.
    The provisional P-DP rates filed with FERC have been updated from 
the rates originally proposed in the customer brochure and Federal 
Register notice dated May 8, 1992. The changes to the Ratesetting PRS 
are summarized as follows:

--Multiproject costs were updated through September 30, 1991. The PAO 
is heavily involved in the process of total quality improvement and has 
a Process Improvement Team (PIT) evaluating the multiproject cost 
process. This PIT is made up of representatives from Engineering, 
Operations, Budget, Finance, and Rates. Recommendations concerning an 
improved process are expected to be published and implemented (if 
approved) early in 1994. To the extent implemented recommendations make 
a change in multiproject cost allocations and in rates, changes will be 
reflected in subsequent rate processing.
--Replacement and addition projections in the cost evaluation period 
were changed to incorporate ``The Engineering Ten-Year Construction and 
Replacement Plan'' dated July 1992 for the cost evaluation period.
--Extraordinary costs were excluded from out years (FY 1998-2047) 
resulting in minor reductions in estimates of O&M costs.
--Future-year replacements in FY 1998-2047 are projected at the most 
current interest rate of 7.875 percent as compared to the FY 1991 
interest rate of 8.50 percent.
--Projections used in FY 1992 for O&M, interest expense, and operating 
revenues were updated to FY 1992 actuals as stated in Western's and 
Reclamation's FY 1992 financial statements.
--The proposed P-DP rates for firm power and firm and nonfirm 
transmission service were initially proposed as a single-step rate 
increase effective for a 5-year period beginning October 1, 1993. 
However, in response to customer comments, Western is proposing to 
implement a two-step rate process. Step one of the provisional P-DP 
rates will become effective February 1, 1994. Step two of the 
provisional P-DP rates will become effective October 1, 1995.
--The FY 1993 purchased power expense has been updated.
    The existing and provisional annual revenue requirements for the P-
DP* are as follows:
---------------------------------------------------------------------------

    *The first steps of the provisional P-DP rates are in effect 
from February 1, 1994, through September 30, 1995. The second steps 
of the P-DP provisional rates are in effect from October 1, 1995, 
through January 31, 1999, or until superseded. 

                      Annual Revenue Requirements                       
------------------------------------------------------------------------
                           Provisional step one    Provisional step two 
        Existing            rates (FY 1994-95)      rates (FY 1996-98)  
------------------------------------------------------------------------
$28,348,137............        $36,083,885              $42,068,860     
------------------------------------------------------------------------

    The rate increase is necessary to satisfy the cost-recovery 
criteria set forth in DOE Order No. RA 6120.2.

Apportionment of Cost Study

    The provisional P-DP rates for firm and nonfirm transmission 
service were based on the Apportionment of Cost Study that analyzed the 
split between annual transmission service and power service costs. The 
firm transmission service rate is established to assure that the P-DP 
customers have an equitable share in payment of costs associated with 
the P-DP transmission system. The beneficiaries of the P-DP 
transmission system include customers for firm electric service, firm 
transmission service, and firm transmission service for SLCA/IP power.
    The Apportionment of Cost Study, dated FY 1977, determined an 
apportionment of 55 percent and 45 percent for power costs and 
transmission costs respectively. The latest Apportionment of Cost 
Study, dated FY 1992, determined separate apportionments for step one 
of the provisional P-DP rates and step two of the provisional P-DP 
rates. The apportionments for step one of the provisional P-DP rates 
are 34.11 percent for power costs and 65.89 percent for transmission 
service costs. The apportionments for step two of the provisional P-DP 
rates are 25.82 percent for power costs and 74.18 percent for 
transmission service costs.
    Since the 1977 Apportionment of Cost Study was completed, P-DP's 
initial power investment has been repaid and the transmission system 
has deteriorated, requiring more replacement and refurbishment 
activities. These factors are causing a shift from power to 
transmission service related costs in the Apportionment of Cost Study. 
The provisional P-DP rates for firm transmission service will earn an 
additional annual amount of $5,670,495 from 1994-95 and $9,857,542 from 
1996-2047.
    The current Apportionment of Cost Study derives the percentage of 
required revenues to be recovered from firm power customers and firm 
transmission customers. The study is performed separately for each step 
of the P-DP provisional rates. Western has adopted a three-step process 
that evaluates capital expenditures, annual operating expenses and 
other revenue, and customer use of the P-DP transmission system. The 
first step of the study assigns project investments to either the power 
system or the transmission system. This step is used in the second step 
of the Apportionment of Cost Study.
    The second step entails apportioning annual operating costs and 
other revenues to either the power system or the transmission system. 
Annual operating costs and other revenues were determined by taking an 
annual average of future years in the cost evaluation period. Annual 
costs include O&M, multiproject, CSRS, interest, and principal 
payments. Other revenues include rent and miscellaneous, fuel 
replacement, multiproject, project use, and nonfirm transmission 
service. If an annual operating cost or a component of other revenue 
was determined to benefit both the power and transmission system, the 
apportionment was assigned in accordance with the apportionment of 
investment costs derived in the first step.
    The transmission system is used to deliver power committed under 
electric service contracts. Therefore, a portion of the transmission 
system cost should be recovered by power sales revenues. The third step 
of the Apportionment of Cost Study determines the share of transmission 
costs to be recovered by power sale revenues. Annual costs are assigned 
to transmission or power production on the basis of power system use by 
each customer. The assignment by use is based upon contract capacity 
commitments for the P-DP transmission system. Users of the P-DP 
transmission system include customers for (1) P-DP wholesale firm 
energy, (2) P-DP firm transmission service, (3) SLCA/IP firm 
transmission service, and (4) project use. Commitments under 
transmission service agreements are assigned to transmission, while 
commitments under electric service contracts and project use are 
assigned to power production. The tables below show the development of 
revenue requirements from power sales and transmission service 
agreements and the assignment of cost into their related revenue 
categories.

          Step One P-DP Provisional Rates Apportionment of Cost         
------------------------------------------------------------------------
                             Total           Power         Transmission 
------------------------------------------------------------------------
Required Revenue.......     $26,087,096      $5,691,780     $20,395,316 
Contract Capacity                                                       
 Commitments...........    1,790,191 kW      281,515 kW    1,508,676 kW 
Percent of Total                                                        
 Capacity..............            100%          15.73%          84.27% 
Assign 15.73 Percent                                                    
 Transmission to Power.  ..............      $3,207,249     ($3,207,249)
Total Required Revenue.     $26,087,096      $8,899,029     $17,188,067 
Percentage to Be                                                        
 Applied in Rate Design            100%          34.11%          65.89% 
------------------------------------------------------------------------


          Step Two P-DP Provisional Rates Apportionment of Cost         
------------------------------------------------------------------------
                             Total           Power         Transmission 
------------------------------------------------------------------------
Required Revenue.......     $31,061,469      $3,925,744     $27,135,725 
Contract Capacity                                                       
 Commitments...........    1,865,665 kW      281,515 kW    1,584,150 kW 
Percent of Total                                                        
 Capacity..............            100%          15.09%          84.91% 
Assign 15.09 Percent                                                    
 Transmission to Power.  ..............      $4,094,580     ($4,094,580)
Total Required Revenue.     $31,061,469      $8,020,324     $23,041,145 
Percentage to Be                                                        
 Applied in Rate Design            100%          25.82%          74.18% 
------------------------------------------------------------------------

    The P-DP provisional rates for firm power and firm and nonfirm 
transmission service are based on the apportionment percentages applied 
to additional annual revenue requirements as derived in the Ratesetting 
PRS.

Alternative Transmission Rates

    As stated in the Federal Register notice published on May 8, 1992 
(57 FR 19904), Western proposed alternative P-DP rates for both firm 
and nonfirm transmission service. The proposed alternative rates would 
have set a single rate for the use of either or both the P-DP and the 
AC Intertie transmission systems. However, based on customers' 
requests, Western decided not to propose the alternative transmission 
service rates at this time.

Replacement and Addition Activities

    The provisional P-DP rate adjustments are due largely to an 
increase in replacements and additions on P-DP. P-DP is undergoing a 
major replacement and refurbishment plan needed for environmental 
compliance, safety, and reliability. Western initially used data from 
the FY 1993 construction budget for replacement and addition activities 
during the CEP (1994-98). However, during the consultation and comment 
period, Western decided to reevaluate the replacement and addition 
activities because of the economic strain being placed on the P-DP 
customers and because of the unrealistic expectations that all 
replacement and addition activities would be completed during the CEP. 
Western compared the data from the FY 1993 construction budget 
documents with the most current construction data as stated in ``The 
Engineering Ten-Year Construction and Replacement Plan'' dated July 
1992. The Engineering Ten-Year Plan showed the most current 
construction data Western had on replacement and addition activities 
over the next 10 years. Western made the decision to revise the 
Ratesetting PRS by incorporating the most current data from the 
Engineering Ten-Year Plan. All of the replacements and additions in the 
Ratesetting PRS are authorized power system facilities for which 
Congress has appropriated funds for FY 1993 construction, and which 
will be in service within the CEP. Thus, the Ratesetting PRS only 
incorporates the first 5 years of the Engineering Ten-Year Plan. These 
revisions, based on data from the Engineering Ten-Year Plan, will help 
maintain the lowest rate possible without jeopardizing the crucial need 
of a safe and reliable P-DP transmission system. A comparison of the 
initial ratesetting PRS using the FY 1993 construction budget to the 
Ratesetting PRS using the Engineering Ten-Year Plan follows:

   FY 1993 Construction Budget vs. Engineering Ten-Year Plan ($1,000)   
------------------------------------------------------------------------
                               FY 1993                                  
 Addition and replacement    construction   Engineering ten-  Difference
       activities              budget          year plan                
------------------------------------------------------------------------
Five-Year Plan/Year in         $8,846/1992  $10,065/19941..      $1,219 
 Service.                                                               
Five-Year Plan (Phase 2)/      11,268/1994  12,327/1995....       1,059 
 Year in Service.                                                       
ED-5 Substation/Year in         3,238/1997  Will be              (3,238)
 Service.                                    completed                  
                                             beyond the CEP.            
Phoenix Substation/Year         9,466/1992  9,525/19941....          59 
 in Service.                                                            
Replace Mesa Substation/        2,774/1992  Combined with        (2,774)
 Year in Service.                            Rogers                     
                                             Substation.                
Rogers Substation/Year in       1,525/1993  6,745/1994 (see       5,220 
 Service.                                    #5.                        
Replace SCADA System/Year      10,970/1993  12,765/1994....       1,795 
 in Service.                                                            
Davis Switchyard/Year in        3,238/1993  3,607/1994.....         369 
 Service.                                                               
Maricopa Substation/Year          156/1993  Will be                (156)
 in Service.                                 completed                  
                                             beyond the CEP.            
Coolidge Substation/Year        6,677/1994  7,456/1994.....         779 
 in Service.                                                            
ED-2 Substation/Year in         5,670/1994  7,963/1995.....       2,293 
 Service.                                                               
Gila/Gila Valley                1,177/1995  Will be              (1,177)
 Transmission Line/Year                      completed                  
 in Service.                                 beyond the CEP.            
Signal Substation/Year in       1,535/1995  Will be              (1,535)
 Service.                                    completed                  
                                             beyond the CEP.            
Maintenance Facilities at       2,728/1995  Will be              (2,728)
 Gila/Year in Service.                       completed                  
                                             beyond the CEP.            
Maintenance Facilities at       3,123/1995  2,209/1995.....        (914)
 Coolidge Substation/Year                                               
 in Service.                                                            
Basic Substation/Year in       16,347/1995  17,236/1995....         889 
 Service.                                                               
Hoover-Mead Basic Line          6,997/1995  4,189/1996.....      (2,808)
 Upgrade/Year in Service.                                               
Gila Substation/Year in         9,390/1996  Will be              (9,390)
 Service.                                    completed                  
                                             beyond the CEP.            
Maricopa-Saguaro 115-kV        15,238/1997  Will be             (15,238)
 Transmission Line/Year                      completed                  
 in Service.                                 beyond the CEP.            
Mead Substation Stage 5/        1,440/1994  1,430/1994.....         (10)
 Year in Service.                                                       
ED-4 Substation/Year in         5,685/1994  8,919/1995.....       3,234 
 Service.                                                               
                          ----------------------------------------------
Total Difference.........  ...............  ...............     (23,052)
------------------------------------------------------------------------
\1\As of October 1, 1993, the 5-Year Plan and the Phoenix Substation    
  have not been completed. Western is assuming these construction-work- 
  in-process activities will be completed plant in service in FY 1994.  

    There are other replacement and addition activities in Western's 
O&M budget documents which are not included in the Engineering Ten-Year 
Plan. These items are mostly communication equipment, including 
microwave equipment and remote terminal units. Each of these O&M budget 
activities was compared to the most recent data and revised to reflect 
an overall reduction of $1.5 million in FY 1997. Western will continue 
to evaluate the implementation of the Engineering Ten-Year Plan and 
adequacy of the provisional P-DP rates and will include any changes in 
future rate adjustments.
    The capitalized costs for future replacements and additions in the 
cost evaluation period include IDC. The IDC calculation for each 
replacement is determined by the interest rate in the year construction 
begins. The annual interest expense for replacements and additions is 
also based on the interest rate in the year construction begins. The 
cumulative investment cost for replacements through the cost evaluation 
period is $115,859,859. The cumulative investment cost for additions 
through the cost evaluation period is $126,839,043.
    The replacement program is used to forecast replacements in years 
1999-2047. The replacement program showed low replacement levels in 
some FYs and high levels in other years. Western believes that only a 
certain amount of work can be done in any given year. Therefore, 
Western decided to average the replacement numbers to reflect a stable 
level of replacements which could be supported over the long term.

Purchased Power Expense

    The consultation and comment period was reopened due to the 
increase in purchased power expense for FY 1993. Data for purchased 
power were initially based on the FY 1993 congressionally approved 
budget. However, during FY 1993, current actual expenses for purchased 
power far exceed the original FY 1993 congressional budget estimate of 
$700,000. The current expenses for purchased power for FY 1993 are 
$5,000,000. This change in purchased power expense has led to an 
increase in the firm power rate. The increase in purchased power 
expense resulted from flooding conditions along the Colorado River in 
southwestern Arizona, which created a generation deficiency.

Statement of Revenue and Related Expenses

    The following table provides a summary of revenue and expense data 
for the 5-year provisional rate approval period.

   Parker-Davis Project: Comparison of 5-Year Rate Period  (1994-98);   
                          Revenues and Expenses                         
                        [In thousands of dollars]                       
------------------------------------------------------------------------
                                      FY 1987   Ratesetting             
                                      PRS, FY     PRS, FY     Difference
                                      1994-98     1994-98               
------------------------------------------------------------------------
Revenues:                                                               
  Project Use.....................       6,025        6,025           0 
  Firm Commercial.................      51,946       68,100      16,154 
  Transmission and Other Revenue..      39,642      124,249      84,607 
  Cumulative Surplus..............   \1\11,309            0     (11,309)
  Capitalized Expenses............           0            0           0 
                                   -------------------------------------
    Total Revenues................     108,922      198,374      89,452 
Revenue Distribution:                                                   
  Operations and Maintenance......      78,961      125,938      46,997 
  Purchased Power.................           0        2,800       2,800 
  Interest Expense................       2,006       55,738      53,732 
  Other Deductions................           0        2,619       2,619 
  Investment Repayment\2\.........      27,955       11,279     (16,676)
  Cumulative Surplus..............           0            0          (0)
                                   -------------------------------------
    Total.........................     108,922      198,374      89,452 
Principal Payments:                                                     
  Payments on Deficit.............           0        5,392       5,392 
  Payments on Project.............           0            0           0 
  Payments on Additions...........           0        5,887       5,887 
  Payments on Replacements........      27,955            0     (27,955)
  Payments on Irrigation Aid......           0            0           0 
                                   -------------------------------------
    Total.........................      27,955       11,279     (16,676)
Cumulative Investment (as of FY                                         
 1998):                                                                 
  Project.........................     108,338      108,338           0 
  Additions.......................      31,561      126,839      95,278 
  Replacements....................      71,640      115,860      44,220 
  Irrigation Aid..................      26,770       26,770           0 
                                   -------------------------------------
    Total.........................     238,309      377,807     139,498 
Unpaid Federal Investment (as of                                        
 FY 1998):                                                              
  Project.........................           0            0           0 
  Additions.......................           0       65,169      65,169 
  Replacements....................      25,170       89,908      64,738 
  Irrigation Aid..................           0            0           0 
    Total.........................      25,170      155,077     129,907 
------------------------------------------------------------------------
\1\Cumulative surplus applied FY 1994.                                  
\2\Includes principal payments for capitalized deficits, replacements,  
  and additions.                                                        

Basis for Rate Development--P-DP

Firm Power Rate

    The provisional firm power P-DP rate was designed to reflect the 
power/transmission split as derived in the Apportionment of Cost Study 
and continues to maintain a 50/50 split between revenue from energy and 
capacity rates based on a 60-percent load factor.
    Step one of the provisional P-DP rates consists of a 5.79 mills/kWh 
energy rate and $2.54/kW/month capacity rate effective February 1, 
1994. The necessary composite rate is 11.58 mills/kWh, which is an 
increase of 28 percent over the existing composite rate of 9.03 mills/
kWh.
    Step two of the provisional P-DP rates consists of a 6.01 mills/kWh 
energy rate and $2.63/kW/month capacity rate effective October 1, 1995. 
The necessary composite rate is 12.01 mills/kWh, which is an increase 
of 33 percent over the existing composite rate of 9.03 mills/kWh.

Transmission Service Rates

    The provisional firm transmission service P-DP rate was designed to 
reflect the power/transmission split as derived in the Apportionment of 
Cost Study. Step one of the provisional P-DP rates for firm 
transmission service is $10.40/kW/year ($.87/kW/month) and nonfirm 
transmission service is 1.98 mills/kWh. The step-one rate for firm 
transmission service for SLCA/IP is $5.20/kW/season ($.87/kW/month). A 
season for the firm transmission service rate for SLCA/IP is 6 months.
    Step two of the provisional P-DP rates for firm transmission 
service is $12.55/kW/year ($1.05/kW/month) and nonfirm transmission 
service is 2.39 mills/kWh. The step two rate for firm transmission 
service for SLCA/IP is $6.27/kW/season ($1.05/kW/month).

Comments

    During the 143-day comment period, Western received 31 written 
comments. In addition, nine speakers commented during the September 11, 
1992, public comment forum. During the reopening of the comment forum 
of an additional 70 days, Western received 19 written comments. In 
addition, seven speakers commented during the July 14, 1993, public 
comment forum. All comments were reviewed and considered in the 
preparation of this rate order.
    Written comments were received from the following sources:

Aguila Irrigation District (Arizona)
Ak-Chin Indian Community (Arizona)
Arizona Municipal Power Users' Association (Arizona)
Arizona Power Pooling Association (Arizona)
Arizona Public Service Company (Arizona)
Buckeye Water Conservation & Drainage District (Arizona)
Basic Management, Inc. (Nevada)
Central Arizona Water Conservation District (Arizona)
Chemstar Lime Company (Arizona)
Colorado River Commission of Nevada (Nevada)
Electrical District Number Two, Pinal County (Arizona)
Electrical District Number Five, Pinal County (Arizona)
Electrical District Number Seven (Arizona)
Harquahala Irrigation District (Arizona)
Irrigation and Electrical Districts Association of Arizona (Arizona)
Maricopa Water District (Arizona)
McMullen Valley Water Conservation and Drainage District (Arizona)
Metropolitan Water District of Southern California (California)
Meyer, Hendricks, Victor, Osborn & Maledon (Arizona)
Nevada Power Company (Nevada) 25 Overton Power District No. 5 
(Nevada)
Pioneer Chlor-Alkali (Nevada)
Roosevelt Irrigation District (Arizona)
Roosevelt Water Conservation District (Arizona)
Safford, City of, Arizona, (Arizona)
Salt River Project (Arizona)
San Carlos Irrigation and Drainage District (Arizona)
Southern California Edison (California)
Titanium Metal Corporations (Nevada)
Tonopah Irrigation District (Arizona)
Valley Electric Association, Inc. (Nevada)

    Representatives of the following organizations made oral comments:

Arizona Power Authority--Leroy Michael, Jr. & David Helsby (Arizona)
Basic Management, Inc.--Richard F. Brown. (Nevada)
Colorado River Commission of Nevada--Thomas Cahill, Don Allen, and 
David Luttrell (Nevada)
Five Hoover Customer Entities--Jay I. Moyes (Arizona)
Irrigation & Electrical Districts Association of Arizona--Robert S. 
Lynch (Arizona)
Overton Power District No. 5 and Valley Electric Association--Jim 
McManus (Nevada)
Pioneer Chlor-Alkali Company--Terry Graves (Nevada)
Salt River Project--Leslie James & Jim Transgrud (Arizona)

    Most of the comments received at the public meetings and in 
correspondence dealt with costs of annual expenses, replacements and 
additions, the proposed alternative transmission service rates, 
consideration of stepped rates, and the Apportionment of Cost Study. 
All comments were considered in developing the provisional P-DP rates.
    The comments and responses, paraphrased for brevity, are discussed 
below. Direct quotes from comment letters are used for clarification 
where necessary.

Parker-Davis Comments

Operation and Maintenance Costs

    Comment: Western's ``General Western Allocation'' expenses are too 
high and they are unfairly charged to P-DP. Western should explain the 
justification of the allocating of costs from its Washington, D.C., and 
Golden, Colorado, offices.
    Response: Western's indirect costs are divided into three 
categories: Associated direct expense (ADE), administrative and general 
expense (AGE), and general Western allocation (GWA). ADE consists of 
undistributed costs and expenses for all types of direct costs which 
possess a clear relationship to benefiting activities and are recovered 
in the power rate base. AGE costs are general and administrative 
expenses benefiting ratepayers and represent primarily costs for 
nonmanagerial staff and support. GWA is a subset of AGE and includes 
ADP expenses, general office supplies, contracted administrative 
services, etc. Independent auditors have determined that AGE and GWA 
exclusively benefit ratepayers and should be recovered as part of the 
costs included in the power rate base. The indirect cost distribution 
system was designed and endorsed by a major accounting firm and is 
consistent with industry standards. Western does not believe these 
costs are excessive in the manner in which they are distributed.
    Comment: In light of the extensive replacement and addition program 
being carried out by Western, O&M costs are not projected to decline in 
the future as supposedly older, high maintenance equipment is replaced 
with newer, lower maintenance equipment.
    Comment: Western feels it is necessary to overestimate operation 
and maintenance expenses as some sort of safeguard in the budget and 
planning process. This is most recently seen by comparison of budget to 
actual numbers for FY 92. We believe a sharper pencil should be taken 
to those O&M projections in the process.
    Response: O&M costs are projected in the future in accordance with 
DOE Order No. RA 6120.2. It is Western's policy, as in section 10, 
paragraph 2(f) of DOE Order No. RA 6120.2, to estimate O&M costs based 
on historical cost trends and actual project costs from the past. 
During the cost evaluation period, O&M expense is based on the FY 1993 
budget, and projections for FY 1999 through FY 2047 are held constant 
based on the last year in the cost evaluation period less extraordinary 
maintenance. O&M does decline in the cost evaluation period. Western 
has a cost containment committee which reviews and evaluates the O&M 
budget. The committee's goals are to achieve the lowest O&M budget 
possible for Western. Therefore, Western does not believe that 
projections for the operation and maintenance budgets are overstated.
    Comment: Rate impact analysis was not performed prior to seeking 
congressional authorization for budgeted O&M expenditures.
    Comment: Western and Reclamation have not attempted to limit O&M 
expense.
    Response: Although specific rate impact analyses were not 
performed, Western and Reclamation have placed a priority on cost 
containment. The formation of Western's Cost Containment Committee 
takes into consideration all impacts to the rates. Cost containment 
plays a major role in the preparation of Western's and Reclamation's 
O&M budgets. Western has invited the customers into the planning 
process, which will evaluate programs and rate impacts.
    Comment: Power Accounting and Collection, Conservation and 
Renewable Energy, and Power Marketing and General Resource Planning has 
increased 39.6 percent from FY 1991 and FY 1992. Total O&M increased 
38.0 percent from FY 1991 to FY 1992. The magnitude of projected 
expenditures for O&M on an average annual basis exceeded the rate of 
inflation by 4.1 percent per year.
    Comment: P-DP O&M expenses have run counter to the regional and 
local trends and forecasts for electric utilities. The cost projections 
for replacements and additions for the 5-year rate evaluation programs 
and the study period appear to be singular in the industry from the 
standpoint of magnitude. Since the late 1980's, the trend in the 
Pacific and Rocky Mountain Southwest has been to keep O&M expenses and 
replacement cost increases below the rate of inflation.
    Response: Western has revised the PRS to reflect actual 
expenditures in FY 1992. Power Accounting and Collection, Conservation 
and Renewable Energy, and Power Marketing and General Resource Planning 
have increased 5.00 percent from FY 1991 to FY 1992. One contributing 
factor to the increased O&M is that the consolidation of the Boulder 
City Area Office and the Phoenix District Office was made during FY 
1991, having an effect on staffing levels and work being performed. 
Specific division (e.g., power marketing) activities were put off until 
the division could acquire staff. The average increase of O&M cost per 
year over the cost evaluation period is 1.46 percent, which is below 
the rate of inflation.
    Comment: Western has failed to explain why administrative and 
general costs increased dramatically following the move of its regional 
office to Phoenix and the consolidation of its other offices, 
particularly since WAPA claimed that these changes would reduce costs 
by $1.5 million annually.
    Response: Western's administrative and general costs have not 
dramatically increased since moving the regional office to Phoenix and 
consolidating other offices. According to Western's FY 1992 financial 
statement, the general Western allocation portion for the Phoenix Area 
has actually decreased from $2.6 million in FY 1991 to $2.2 million in 
FY 1992, which represents a decrease of 15 percent. The Phoenix Area's 
AGE also decreased from $1.5 million in FY 1991 to $1.3 million in FY 
1992, which represents a decrease of 13 percent. Western had estimated 
an overall savings of $1.5 million annually. However, the consolidation 
was not completed until FY 1992. Western believes the full recognition 
of savings from the consolidation has not yet become evident.

Alternative Transmission Rates

    Comment: Customers renew their support for the alternative 
transmission rates.
    Comment: Customers do not support the alternative transmission 
rates because of subsidizing and project repayment issues. Each 
transmission project should be planned, designed, and operated on its 
own merit.
    Response: Since Western and the customers agreed not to recommend 
implementation of the alternative transmission service rates, Western 
plans to implement separate P-DP and AC Intertie rates for firm 
transmission service and nonfirm transmission service.
    Comment: Western should conduct further studies to determine the 
feasibility of complete operational integration of the various 
transmission facilities in the Phoenix Area.
    Response: Operationally, PAO's power systems are integrated. Power 
marketing functions will continue to be performed separately for each 
individual project. Western will continue to work with the customers in 
conducting studies and evaluating other alternatives for developing a 
single transmission rate for the various projects within the PAO.

Apportionment of Cost Study

    Comment: The cost allocation review of historic Western O&M 
expenses shows no dollars being charged against the power function on 
an actual basis, which is inconsistent with the facts.
    Comment: The use of historical costs are not relevant to the 
Apportionment of Cost Study because the historical costs do not affect 
the proposed rates.
    Response: Western has revised the Apportionment of Cost Study to 
reflect customer comments. The revised study does not include 
historical Western O&M expenses because the historical costs do not 
affect the provisional P-DP rates.
    Comment: Western should adopt a reasonable or fair allocation by 
splitting the difference between the historic 45/55-percent split and 
the proposed 77/23-percent split or retain its historic allocation 
until a detailed study can be conducted regarding what amount of actual 
Western O&M should be assigned to power.
    Response: Western believes the revised Apportionment of Cost Study 
is an equitable and detailed study that apportions the costs between 
power production and transmission service. The 45/55-percent split was 
based on a study presented in the June 1979 rate adjustment brochure 
for P-DP. Since that time, there has been a shift from power costs to 
transmission costs, which is due to the initial investment and 
irrigation investment being repaid in 1986. Thus, the majority of the 
investment to be repaid is related to the refurbishment of the 
transmission system. Western's future intent is to evaluate the 
apportionment between power and transmission costs annually and to make 
revisions to the rate design when rate adjustments occur.
    Comment: Western's allocation methodology between generation and 
transmission does not follow the accepted practice in expensing capital 
costs and allocating other income. Western should propose a change by 
allocating annual principal and interest based on generation and 
transmission plant original cost depreciated.
    Response: The Apportionment of Cost Study has been revised to 
expense capital costs and allocate other income based on total 
generation and transmission investment. However, Western also 
considered the unpaid Federal investment with regard to annual 
principal and interest costs. Western has determined that the unpaid 
Federal investment is a transmission related cost. Therefore, annual 
principal payments and interest costs for the unpaid investment will be 
allocated to transmission.
    Comment: The functions of power scheduling and power marketing are 
power related. Furthermore, some percentage of FTEs should have been 
charged against the power function.
    Response: Western has revised the Apportionment of Cost Study that 
is incorporated into the PRS to allocate a percentage of power 
scheduling, FTEs, and power marketing to power related costs. The 
percentage used for allocating these costs is based on the percentage 
of total power investment to the total investment.
    Comment: Western did not allocate the power and transmission 
related costs to customer classes.
    Response: Western allocated the power and transmission related 
costs to customer classes based on power system use by each type of 
customer. Users of the P-DP transmission system include customers for 
(1) P-DP wholesale firm energy, (2) P-DP firm transmission service, (3) 
firm transmission service for SLCA/IP, and (4) project use. Commitments 
under transmission service contracts are assigned to transmission while 
commitments under electric service contracts and project use are 
assigned to power production. Western believes this is an equitable way 
of allocating power and transmission costs among the customers.
    Comment: The Allowance for Interest in Western's Apportionment of 
Cost Study does not conform to Western's PRS. We understand that 
Western is aware of this discrepancy, and we recommend that the proper 
correction be made.
    Response: Western has corrected the Allowance for Interest in the 
Apportionment of Cost Study so that it conforms to the PRS.
    Comment: Irrigation investment in the amount of $26.8 million has 
been assigned by Western to transmission, but should be assigned to 
power. The irrigation investment represents an assignment of certain 
hydraulic plants to irrigation and has no relationship to transmission.
    Response: The Apportionment of Cost Study uses Western's and 
Reclamation's FY 1992 financial statements, budget documents, and the 
Engineering Ten-Year Plan to determine the investments that are 
allocated to power and the investments that are allocated to 
transmission. Investments stated in Western's financial statement and 
Engineering Ten-Year Plan are considered transmission investments, and 
investments stated in Reclamation's financial statement and FY 1993 
budget are considered power investments. Irrigation investment is in 
Reclamation's financial statement. Therefore, the irrigation investment 
in the amount of $26.8 million is already assigned to power in the 
Apportionment of Cost Study.
    Comment: An investment in FY 1990 of $3.4 million in account 331 
(Hydraulic Production--Structures and Improvements) was assigned by 
Western to transmission, but should be assigned to power.
    Response: The investment in FY 1990 of $3.4 million in account 331 
(Hydraulic Production--Structures and Improvements) is shown in the P-
DP replacement study. The P-DP replacement study incorporates both 
Western's and Reclamation's investments as stated in each of the 
agencies' financial statements. Western has made the assumption that 
investments appearing in Reclamation's financial statements would be 
allocated to power and investments appearing in Western's financial 
statements would be allocated to transmission. The replacement study 
was not used as a source document for the Apportionment of Cost Study.
    Comment: Existing and future investments in communication 
facilities have been assigned entirely to transmission. A more proper 
assignment would be 50 percent to transmission and 50 percent to power 
as is done by Western for the CRSP.
    Response: Western has researched the possibility of assigning 
communication equipment equally between power and transmission. 
Communication equipment includes supervisory control and data 
acquisition (SCADA), microwave system, and the joint use system. In the 
Phoenix area, Reclamation and Western separately budget for microwave 
systems and joint use systems. Western has determined that SCADA is a 
unique investment because it has major benefits to both power and 
transmission customers and it is being funded through Western's FY 1993 
congressional budget. The SCADA system is, among other uses, used to 
regulate power flows on the transmission lines. Because SCADA benefits 
both power and transmission customers, Western has decided that 50 
percent of the costs should be apportioned to power and 50 percent of 
the costs consistency should be apportioned to transmission. Therefore, 
the Apportionment of Cost Study has been changed to reflect the 50/50 
split of the SCADA investment and associated interest expense.
    Comment: Western's new PAO has been assigned entirely to 
transmission. As this office is involved in both power marketing and 
transmission, the cost of these facilities should be borne by both 
power and transmission.
    Response: This comment is incorrect in that the costs associated 
with the new PAO facility have been allocated to both power and 
transmission, with power being allocated approximately 16 percent of 
the costs of said facility. While this may not readily be apparent at 
first glance, analysis of the Apportionment of Cost Study will verify 
this allocation.
    In the Apportionment of Cost Study, Western first determines 
whether the expenditure was funded by Western or Reclamation. All 
expenditures funded by Reclamation are allocated to power. Expenditures 
by Western are further analyzed to determine if they benefit only the 
transmission customers or if they also benefit the power customers 
(from a powerplant or power generation standpoint). To the extent the 
facilities have a direct benefit to the power customers from a power 
generation standpoint, a portion of the costs are allocated to power. 
Western's SCADA system is an example of one of these facilities in that 
although the expenditure is funded totally by Western, both the power 
customers and transmission customers receive benefits from the system.
    Once Western has determined the costs of those facilities which 
benefit the transmission customers, a further allocation of costs is 
conducted. This is due to the fact that the transmission system is 
utilized both by (1) the power customers to transmit their power 
entitlement from the powerplants to their loads and (2) by customers 
who utilize the transmission system for bulk power transfers. It is 
this allocation of costs which properly further allocates costs to 
power and transmission and ensures that within the rates charged to the 
power customers is a component for the use of the transmission system. 
This is why the power customers are not charged a transmission charge 
for their power entitlement. It is this final allocation which ensures 
that the power customers are always responsible for a portion of 
Western costs which are transmission related. As shown in the 
Apportionment of Cost Study, the power users are allocated 
approximately 16 percent of the costs of the new PAO facility.
    Comment: Western assigns project use revenues as an expense offset 
to power costs. Inasmuch as the delivery of this power requires use of 
the P-DP transmission system, it is appropriate to assign these 
revenues (expense offsets) to power and transmission in proportion to 
the plant investments in each category (for step-one rates, the 
allocation would be 31.66 percent to power and 68.34 percent to 
transmission).
    Comment: Customer believes the current allocation of both project 
use revenues and project use sales is correct in Western's 
apportionment study. Classification of sales (kilowatts) as power is 
acceptable, provided the firm power customer classification is directly 
credited with the revenues from the project use sales (kilowatts) as is 
currently done in Western's Apportionment of Cost Study.
    Response: Western believes the current allocation of project use 
revenues is correct in the Apportionment of Cost Study. Project use 
should be allocated to power because sales are also classified as 
power. Further, the costs associated with project use are contained in 
Reclamation's financial statement and budget documents which are also 
assigned to power. Project use costs and benefits have been 
consistently used in the Apportionment of Cost Study so that the 
benefits will offset the costs associated with project use.
    Comment: Based on restrictions on the power customers' use of 
capacity paid for in the power rate and significantly better benefits 
to all other users of the transmission system, we do not feel that the 
allocation of costs according to customer class is correct.
    Response: Western understands the power customers' concerns that 
the Apportionment of Cost Study treats 1 kW of P-DP power transmitted 
over the transmission system the same as 1 kW of non-P-DP power 
transmitted over the transmission system, even though the P-DP power is 
limited to approximately 56 percent capacity factor. However, Western 
believes that because the customers have complete flexibility to 
schedule their power and energy when they want, Western transmission 
must be available to handle the desired transaction. Western bases the 
Apportionment of Cost Study on the kW of ``reservation'' the customers 
have for use of the system and not on the actual kWh usage of the 
system. From this perspective, power customers and transmission 
customers alike pay to have the transmission system reserved for their 
use, regardless of the actual system use.
    Comment: Western should consider a phase-in of what would be a 
significant shift in allocation of costs from transmission to 
generation if the cost apportionment study is adapted.
    Response: In response to the customer comments, Western has decided 
to implement stepped rates for the provisional P-DP rate schedules. The 
first steps of the provisional rates are effective from FY 1994-95 and 
the second steps are effective for FY 1996-98. Step-one rates reflect 
only the replacements and additions proposed by Western for FY 1994-95. 
Step two rates reflect the replacements and additions for FY 1996 
through the end of the study period. Implementing stepped rates will 
lessen the impact on the customers by allowing them to phase-in the new 
rates.

Calculation of Interest During Construction

    Comment: Western should reexamine the procedure for utilizing the 
interest rates in effect at the inception of the project and change the 
regulation accordingly. Western's definition of start of construction 
and charging of IDC should be revised to reflect FERC policy.
    Comment: Western is using the wrong interest rates on replacements 
and additions. The interest rate in effect for each year of a project's 
appropriation should be used and a weighted average rate established on 
completion of the project.
    Response: Western's policy is to utilize the interest rate in 
effect at the inception of the project and Western believes this 
accurately reflects FERC policy and is in accordance with DOE Order No. 
RA 6120.2. IDC accumulates at the appropriate effective interest rate 
for a replacement or addition when the first direct cost (FERC Accounts 
350 and above) is incurred to initiate construction or replacement. 
This interest rate remains constant with the investment. IDC terminates 
at the end of the FY in which the facility is placed in service. DOE 
Order No. RA 6120.2 states that the interest rate to be used for 
computing interest during construction shall be the yield rate during 
the FY in which construction is initiated. Therefore, Western does not 
believe that a weighted average reflects FERC policy or is in 
accordance with DOE Order No. RA 6120.2.
    Comment: Western is using the wrong interest rates on replacements 
and additions.
    Response: Western uses the most current yield interest rates as 
defined by the Department of the Treasury for each FY. This is in 
accordance with the formula set forth in DOE Order No. RA 6120.2, 
paragraph 11(b).
    Comment: It was suggested that Western use the most current 
interest rate.
    Response: At the time of the comment forum, Western was using the 
most current interest rate of 8.5 percent as defined by the Department 
of the Treasury. Since then, Western has revised the Ratesetting PRS to 
reflect the interest rate calculated for FY 1992, which is 7.875 
percent. As a result, interest expense in future years has decreased.

Rate Design

    Comment: In its revised PRS of June 1993, Western has continued to 
use the wheeled kW from early 1992 in the design of its currently 
proposed transmission rate. However, there have been increases to 
Western's transmission capacity under contract, and further increases 
are currently known.
    Response: Western will use the most current contractual amount of 
firm transmission in kW for the design of the firm transmission rate. 
Therefore, the number of kW will increase from 1,411,228 to 1,508,676 
in step one of the P-DP transmission rate. The number of kW will 
increase to 1,584,150 in step two of the P-DP transmission rate.
    Comment: It is improper to burden the existing transmission 
customers with the cost of new capacity, and an allowance for increased 
contracted kW would remedy somewhat this inappropriate burden.
    Response: The only additional transmission facility being added to 
the system is the Mead-Basic #2 line. Further studies need to be 
completed to determine what, if any, additional transmission capability 
is available to the system as a result of the installation of this 
transmission line. In the event Western adds additional transmission 
capability to the system and contracts for the additional capacity, 
this would be reflected in the Apportionment of Cost Study for future 
PRSs.
    Comment: Western should implement multistep rates, designed to meet 
annual financial obligations without prepayment of debt. A multistep 
rate would be designed to meet annual financial obligations.
    Response: FERC approves rates for a 5-year period. These rates have 
to produce adequate revenues that will recover all annual costs and 
will repay project investments in no longer than a 50-year period. 
Rates cannot be approved by FERC beyond the 5-year window. If multistep 
rates were designed outside the 5-year window, then the rates within 
the 5-year window would not adequately recover all costs and repay 
project investment over a 50-year period. Thus, the requirements of DOE 
Order No. RA 6120.2 would not be met. However, within the 5-year 
period, Western has decided to implement a two-step rate process, so 
the customers can phase-in the significant rate increase.
    Comment: The rate design method does not reflect or adjust to 
changes in the cost of service for each customer classification which 
will occur over time. Western is only applying the results of the 
Apportionment of Cost Study to the incremental revenue requirement 
above that which can be met by the current rates. The net result is 
dilution of the transmission contractor's financial obligation at the 
expense of the power customers.
    Comment: Western compounds its errors by allocating only the 
incremental part of the rate increase to power and transmission. The 
rate design should be based upon total revenue requirements, not 
incremental revenue requirements.
    Response: Western understands the negative aspects of only 
allocating the incremental part of the rate increase between power and 
transmission. However, the customer is assuming that the past 
apportionment of 55 percent for power and 45 percent for transmission 
was incorrect. Western believes the last apportionment between power 
and transmission is correct, meaning that the rate design should be 
incremental. Each year, Western will perform an Apportionment of Cost 
Study to stay abreast of the incremental change from year to year. The 
reason for the large incremental change from power to transmission is 
that the original project has been fully repaid and the transmission 
system is deteriorating and must be refurbished.

Replacements and Addition Activities

    Comment: Errors may exist in the assignment of replacement and 
addition costs between P-DP customers and Federal agencies. Western did 
not examine other sources of funding.
    Comment: The proposed increase is excessive since it includes 
extensive refurbishment in the Phoenix Area which does not support the 
path over which service is provided.
    Response: The need for projected replacements and additions has 
been previously examined and justified through the O&M and engineering 
budget process. Projected replacements and additions have been 
identified in Western's Engineering Ten-Year Plan, along with Western's 
FY 1993 Budget documents. Further, facility development reports have 
been developed which analyze the costs and benefits to Western. 
Although Western receives some funding through trust and reimbursables 
the majority of the costs that benefit the system as a whole are placed 
into the rate base. Western has included the customers in the planning 
process. This will allow the customers to help Western examine sources 
of funding and plan extensive refurbishment in the Phoenix Area.
    Comment: When did the replacement and addition program begin and 
what is the current status of the program?
    Response: During FY 1991, Western developed the Engineering Ten-
Year Plan which was a planning tool for ongoing replacement and 
addition activities. In June 1993, Western invited the customers to 
participate in developing the engineering 10-year planning process. 
Western is currently working with the customers in updating and 
revising the Engineering Ten-Year Plan. It is Western's intention to 
update and evaluate the Engineering Ten-Year Plan annually with the 
customers.
    Comment: Western has based its decisions to replace facilities and 
equipment on the age of the facility and equipment or on Western's 
desire to try out new equipment technologies. The replacement and 
addition program was not planned, designed, scheduled, or maintained to 
best serve the customers. There is concern on how well Western has 
managed its program.
    Comment: Western has not designed facilities in a cost-effective 
manner.
    Comment: Concerning its replacement and addition program (program), 
Western did not (i) perform appropriate planning analysis, (ii) assess 
program impact on rates prior to implementation, (iii) inform customers 
of program, (iv) seek input from customers, or (v) minimize magnitude 
of program. Western has not attempted to schedule or prioritize work to 
minimize rate impact.
    Response: Western utilizes accepted utility design standards and 
detailed engineering economic studies in determining, planning, and 
executing construction and replacement projects. These standards and 
studies are described in Western's FDRs for each major construction 
project. Furthermore, the purpose of the Engineering Ten-Year Plan is 
to effectively design, plan, prioritize, schedule, and analyze rate 
impacts on all the Phoenix Area Projects. Western believes that future 
rate impacts are minimized and costs can be controlled through this 
process. Western is now including the customers in the planning process 
so they are informed and may provide input on future construction 
activities. By including the customers in this process, Western will 
minimize rate impacts and meet customers' needs.
    Comment: A fixed amount for replacements of $4.3 million in future 
FY 1998-2047 cannot be representative of future replacements when 
practically the entire system will have been replaced by 1998.
    Comment: Western should make a commitment to limit replacements to 
$4.3 million or less after 1997 unless authorized by the working 
committee.
    Response: Western believes the $4.3 million average is a good 
representation of the future replacement costs and is based on the 
replacement program which reflects historic experience and service 
lives of project equipment and facilities. Western cannot commit to a 
fixed amount when the amounts are based on actual experience and an 
annual budget document, which change over time.
    Comment: Western optimistically forecast savings and did not 
consider the full and true cost of its 5-Year Plan, phase two of the 
Phoenix Office, plus the total replacement and addition investment 
levels, to determine the overall impact on P-DP rates.
    Response: Western believes that the benefits of consolidation are 
just beginning to be recognized and once the consolidation process is 
completed, there will be additional long-term savings. Prior to the 
decision to consolidate the Phoenix District Office with the Boulder 
City Area Office, Western conducted a cost/benefit analysis that 
included replacement and addition investments. This study analyzed the 
costs and benefits of five different options of which the option to 
consolidate the Phoenix District Office and the Boulder City Area 
Office indicated the highest cost savings. This option also indicated 
the lowest rate impacts. The study concluded (among other things) that 
planned construction at Phoenix can be modified and expanded at a 
reasonable cost to accommodate the Area functions and increase office 
space. However, it also indicated that there would be disruption of 
continuity for up to 2 years and that there would be additional 
construction costs.
    Comment: Western's replacement and additions program is not 
justifiable.
    Comment: Western is attempting to replace a large portion of the 
facilities over a 10-year period. The replacement costs and the 
administration and general costs of administering the replacement work 
peaked, making the rate impact abnormally high. It is suggested that 
Western attempt to select a replacement period of 15 to 20 years as 
compared to the Engineering Ten-Year Plan.
    Comment: Western has not explained or justified the astronomical 
increase in replacements from less than $2 million on average for the 
past 10 years to amounts averaging over $14 million for the years 1993 
through 1998.
    Comment: The rate proposal offers considerable discretion in the 
replacement budget area. This includes the time period over which the 
expenditure needs to be made and the necessity of certain expenditures.
    Response: The justification for the replacement and addition 
program is that the P-DP is over 50 years old and is in the process of 
a major refurbishment and replacement program. A large portion of the 
system is deteriorating to the point where safe and continued operation 
to all customers is jeopardized. The Engineering Ten-Year Plan analyzes 
the activities with considerable scrutiny over a period of 10 years and 
will be updated annually. While developing the Engineering Ten-Year 
Plan, Western deferred certain replacement and addition activities 
until a later date. Overall, the Engineering Ten-Year Plan resulted in 
a refurbishment and replacement program that will improve reliability, 
improve personnel safety, increase capacity, and replace out-of-date 
equipment that cannot be repaired.
    Comment: The replacement expenditures after the 5-year evaluation 
period do not reflect the replacements scheduled during the evaluation 
period. As a result, the PRS may include costs for replacements during 
the study period which will actually be replaced during the evaluation 
period.
    Response: The replacement study projects replacements after the 5-
year evaluation period based on the total plant investment as of FY 
1991. Projections during the cost evaluation period (FY 1994-98) are 
based on the replacements indicated in the Engineering Ten-Year Plan. 
Replacements projected during the cost evaluation period will not be 
duplicated in out years, as long as the replacement is made relatively 
close to the end of the equipment's service life. The replacement study 
is based on historic experience and service lives of each type of 
equipment and has proved to be an effective tool for projections.
    Comment: It appears to the customer that Western is, in effect, 
double covering future replacement costs by including the $4.3 million 
annual replacements estimate, notwithstanding the Engineering Ten-Year 
Plan, which includes a full planning horizon 5 years beyond the 5-year 
ratesetting period. The $4.3 million annual replacements projection 
should be eliminated from this rate before filing with FERC, in 
reliance upon the Engineering Ten-Year Plan process and as evidence of 
Western's full-faith commitment with its customers to the Engineering 
Ten-Year Plan concept.
    Comment: Western has the perfect opportunity here to submit this 
rate to FERC without the $4.3 million estimate on replacements in the 
future with the Engineering Ten-Year Plan as the appropriate rationale 
for any deviation from DOE Order No. RA 6120.2 that FERC might consider 
it to be.
    Comment: While it is the general intent of DOE Order No. RA 6120.2 
that Western include allowances for replacements for the entire study 
period of the PRS, DOE Order No. RA 6120.2 also permits a deviation 
from this requirement in paragraph 1. It is recommended that Western 
adopt any reasonable approach to mitigate this large increase. FERC 
addressed the matter of replacements in Docket EF89-5041-000. While we 
may not necessarily agree with the FERC order in its entirety, we 
believe that Western has the ability to deviate from the requirements 
of DOE Order No. RA 6120.2. Therefore, Western should omit from its 
proposed PRS the currently proposed allowances for replacements in the 
amount of $217 million ($4.3 million per year) for years 1998-2047. The 
use of an average amount has helped minimize the rate impact.
    Response: In the recent past, FERC has ruled on a P-DP rate 
adjustment that the PRS should show that revenue produced by the 
provisional P-DP rates is adequate to pay all of the project's annual 
costs, repay investment with interest of the project, and provide for 
payment of replacement costs over the life of the project. Docket No. 
EF 89-5041-000 states:

    Nevertheless, WAPA has failed to recognize replacement costs 
that will be incurred between 1993 and 2042. The draft PRS that WAPA 
provided in response to staff's request provides an indication of 
the extent of these replacements and their considerable costs.
    WAPA has neither complied with Order No. RA 6120.2 nor asserted 
any basis upon which the Commission could find WAPA's interim rates 
``consistent with sound business principles'' or ``sufficient to 
recover the costs of producing and transmitting electric energy . . 
. .'' Under these circumstances, the Commission will exercise its 
delegated authority to remand the interim Parker-Davis rates and to 
direct WAPA either to: 1) file substitute rates and accompanying 
documents in accordance with the terms of this order; or 2) 
alternatively, refile its proposed rates and clearly demonstrate 
that the omission of the replacement costs discussed herein from the 
proposed rates and the PRS has been ``specifically approved by the 
Secretary of Energy, authorized by statute, or identified and 
explained in a transmittal memorandum or in a footnote to the 
reports.''

    Therefore, Western cannot omit the allowances for replacements in 
the amount of $217 million ($4.3 million per year) for years 1998-2047. 
The use of an average amount has substantially mitigated much of the 
impact on rates.
    Western is working with the customers on a review of the 
Engineering Ten-Year Plan of capital additions and replacements and of 
the appropriateness of its incorporation into the PRS. Specifically, 
the customers and Western will examine the use in the PRS of 
projections of future replacements from the Engineering Ten-Year Plan 
versus projections of replacements from the Replacement Study portion 
of the PRS. Western and its customers will examine which future 
replacements projection and revenue requirements are most appropriate 
for reliable operation of the Federal system and setting rates.
    Comment: Customer is concerned about the high concentration of 
replacement and addition costs in FY 1994 and FY 1995 within the rate 
period. History dictates that Western will, in fact, not be able to 
manage or execute those levels of expenditures in short periods of 
time. Please reexamine the expenditures schedule before the rate is 
finalized to avoid any unnecessary pinch-point resulting from 
unrealistic projections.
    Response: Western has reexamined the replacement costs and believes 
the costs used in the PRS for replacements in FY 1994 and FY 1995 are 
appropriate and are the best estimates to date. Western hopes to work 
through the engineering 10-year planning process with the customers to 
reexamine the expenditures schedule. This will not be completed before 
the rate process is completed. However, Western has examined the pinch-
point in the PRS. The step-one rate increase is being set to meet 
annual expenses and interest expense. The step-two rate increase is 
being set to meet required payments needed to fully repay investment.

Purchased Power

    Comment: Purchased power costs do not reflect planned flow releases 
from upstream reservoirs (i.e., $700,000 in purchased power costs 
should be eliminated after FY 1993). On April 8, 1992, Reclamation 
prepared a forecast of water releases through Hoover Dam. This forecast 
is based upon a consumptive water use downstream of Hoover Dam of 7.5 
MAF and a delivery requirement of 1.5 MAF to Mexico. From 1993-97, 
these figures match the flows in 1987, and in 1987, P-DP did not 
purchase power. P-DP generated 482,875,918 kWh in excess of contract 
requirements.
    Response: Western has certain contractual capacity and energy 
commitments to the P-DP contractors, regardless of the forecasted water 
releases from Hoover Dam, the upstream water supplier to Parker and 
Davis Dams. Western calculates the purchased power costs based upon a 
comparison of Reclamation's schedule of downstream water releases with 
the projected energy schedules of the P-DP contractors. While the total 
water releases, on an annual basis, may be sufficient to generate all 
of the energy requirements of the P-DP on an annual basis, the real-
time water release may not match the real-time energy schedules and 
power purchases must be made. The FY 1993 budget reflects Western's 
projection that approximately $700,000 per year would need to be 
budgeted to assure power deliveries to the P-DP contractors. Since the 
derivation of the FY 1993 budget, Western has increased this projected 
expenditure to approximately $2.3 million.
    Comment: Western should reduce the projected expenditures for the 
period May 1993 through September 1993 to correspond to the average of 
previous years.
    Response: Western has changed the PRS to show the most current 
purchased power expense for FY 1993, which reflects the flow 
restrictions last year. This purchased power expense has been reduced 
to $5 million in FY 1993 as compared to the $6.5 million previously 
shown in the addendum to the May 1992 customer brochure dated June 
1993.
    Comment: Please extend the schedule for repayment of capitalized 
purchased power costs and use this tactic, along with other adjustments 
to FY 1994 and FY 1995, to reduce step one for P-DP purchased power 
costs.
    Response: Western has determined through analyzing the PRS that the 
repayment schedule of the capitalized purchased power cost, which is a 
loan to meet annual expenses, is not setting the step-one rate. The 
step-one rate is being set by interest expense in FY 1995. If repayment 
is deferred, the interest expense actually increases. The PRS is 
designed to pay interest expense before it repays any loans. Western 
believes the Ratesetting PRS solves for the lowest rate possible in 
both steps and is in accordance with sound business principles.
    Comment: Western should reexamine the projections for purchased 
power made during the period of January through March and in September. 
Many of Western's customers that serve primarily agricultural loads 
will have reduced loads during these periods. Western has previously 
facilitated exchanges in such situations to reduce the need for 
purchased power.
    Response: Western is willing to work with the customers in resource 
planning initiatives and realizes the importance to mitigate purchased 
power. Western has attempted to use resource integration by exchanging 
energy efficiently to support customer loads. However, this would only 
reduce purchased power expense if a majority of the P-DP customers 
could derive load profiles that matched river regulation restrictions.
    Comment: Western should project some level of nonfirm sales in the 
upcoming years based on historic water demand and projected water 
supply figures from Reclamation. A prudent projection of those 
revenues, including revenues that will be available from mothballing 
the Yuma desalter, should be projected.
    Response: In the Ratesetting PRS, nonfirm sales are projected based 
on a historical average of revenue earned from nonfirm sales. 
Currently, Western is unsure how the mothballing of the Yuma desalter 
will impact revenues, energy, and transmission. Future decisions will 
be reflected in future rate actions.
    Comment: Customers would be better served if the P-DP contracts 
were amended to provide an option to the contractors for Western to 
purchase firming energy on the contractor's behalf, or for Western to 
provide only the energy generated by the P-DP project itself.
    Response: The Phoenix Area is receptive to meeting with the 
customers to discuss possible options. Western believes, however, that 
any course of action chosen should be in the best interest of all 
parties and should be as easy to implement as possible in order to 
minimize the costs of administration.

Working Committee

    Comment: Western should cooperate in the formation of a process to 
allow customer review and input to Western's work plans projected 5 to 
10 years in the future for O&M, replacements, and additions at an early 
enough stage of the planning cycle to have an impact. The creation of 
an Engineering and Oversight Committee would provide for a safeguard 
against overcollection, inflated estimates of projected expenditures, 
an organized dialogue with its customers, and prevent the reoccurrence 
of past overspending in the future.
    Comment: Western should support a customer and agency working 
committee. Included in the working committee should be objectives and 
criteria that relate to balancing the goal of safe and reliable 
operations with the goal of cost containment and other economic 
efficiencies. A year ago, the Arizona Power Authority endorsed a 
proposal to create and empower a P-DP Engineering and Oversight 
Committee as the structure and process for working toward price 
stability. Since then, with customer involvement, Western has started 
two programs that provide promise for working toward the price 
stability goal--the Engineering Ten-Year Plan and the transmission 
planning system.
    Western should continue the formalization of an engineering 10-year 
planning process involving the P-DP customers as initiated by Western 
during the spring of 1993.
    Response: Western supports some type of a customer and agency 
operational working committee. Western is committed to working closely 
with the customers in the development of a customer/agency operational 
working committee and has, in fact, initiated a procedure for allowing 
its customers more advance input into the planning process. Western has 
asked the customers for their help in developing a current Engineering 
Ten-Year Plan. This has allowed Western to organize dialogue with the 
customers and has allowed the customers to provide input on future 
construction activities. Western is currently working with the 
customers to design criteria that will balance the goal of safe and 
reliable operations with the goal of cost containment. Improved 
efficiencies will be a result of including the customers in the 
engineering 10-year planning process. Further, Western believes that 
the participation of the customers in developing the Engineering Ten-
Year Plan and transmission planning system, also referred to as the 
joint-use transmission system, is just the beginning of involvement and 
partnerships Western is hoping to achieve with its customers.

Economic Issues

    Comment: Western should consider emergency cost-cutting measures to 
help Arizona customers and small utilities through these economic 
times.
    Comment: Western should consider the plight of irrigation customers 
when they pass the rate increase costs on to them.
    Comment: At this time, the cost of significant replacements and 
additions on the P-DP cause tremendous strain on Buckeye and its 
customers.
    Comment: Western should consider the effects of the rate increases 
on the agricultural economy in Arizona.
    Comment: Western should postpone the implementation of the rate 
increase.
    Comment: Western's PAO must begin to recognize its responsibilities 
to consumers of Arizona, California, and Nevada and must not forget its 
mission is to market and deliver low cost Federal hydropower to 
preference customers.
    Comment: There is concern about the cost increases in 
transmission's O&M, replacements, and additions that are substantially 
greater than the rate of inflation. Based on decisions that have been 
made, Western should request establishing and empowering a process for 
control of such costs in the future.
    Comment: It is requested that Western consider every possible 
alternative which will reduce the need for such significant rate 
increases.
    Response: Western has reviewed its O&M and replacement costs and 
believes that the costs have been justified. While Western is 
sympathetic to the current financial plight of a number of the 
customers with large agricultural loads, Western and the Bureau believe 
the replacement and addition costs cannot be deferred to a later date 
without jeopardizing safety and reliability. Western realizes that 
replacements and additions exceed the rate of inflation. However, 
Western cannot allow the Parker-Davis facilities to deteriorate to a 
point where safe and continued operation to all customers is 
jeopardized. Western is continuing to look at both its O&M and 
construction plans to determine what, if any, expenditures can be 
avoided or delayed, without sacrificing service to its customers.
    Western believes the mission to market and deliver low-cost Federal 
hydropower to all customers has not been neglected. Western is 
committed to work with its customers to ensure that all entities are 
satisfied regarding the O&M and replacement expenditures. Western, 
along with the customers, will continue to review and revise O&M and 
replacement costs which will meet the needs of the customers and the 
needs of the P-DP system.

General Rate Issues

    Comment: To date, much of the frustration of the customers with 
Western's ratesetting process results from not understanding Western's 
numbers, or where they come from, or the inconsistent sources used 
during the process.
    Response: The numbers used in the PRS are consistent with the 
Engineering Ten-Year Plan and with the FY 1993 budget. Western hopes 
that involving the customers in the engineering 10-year planning 
process will result in a better understanding of how the numbers used 
in the PRS are derived.
    Comment: Western should use the current budget in the current PRS, 
and use the Engineering Ten-Year Plan in future PRSs.
    Comment: The FY 1992 Engineering Ten-Year Plan Western is using 
significantly overstated Parker-Davis expenditures for FY 1993 and FY 
1994, blessed with the hindsight of an actual 1993 budget and a 
requested FY 1994 budget. The rates should reflect these later 
realities.
    Response: Western chose to use the Engineering Ten-Year Plan in the 
Ratesetting PRS because it was the best information available at the 
time. However, the PRS relies on several pieces of data. For instance, 
during the cost evaluation period, the replacements and additions from 
the Engineering Ten-Year Plan were all in the FY 1993 congressionally 
approved budget. The Engineering Ten-Year Plan varies from the FY 1993 
congressionally approved budget in timing of completion of projects and 
amounts to be spent in FY 1994-98. Western is currently meeting with 
the customers to develop a revised Engineering Ten-Year Plan in the 
future that will incorporate customer input. Western plans on using the 
Engineering Ten-Year Plan as a tool in developing the budgets so that, 
in the future, the PRS will be based on budget documents founded in the 
Engineering Ten-Year Plan.
    Comment: Clearly the use of the Engineering Ten-Year Plan is a 
deviation from the requirements of DOE Order No. RA 6120.2. It is for 
the simple reason that it does not, and indeed is not necessarily 
intended to, reflect only investment costs ``for which Congress has 
appropriated funds for construction and which will be in service within 
the cost evaluation period.'' (DOE Order No. RA 6120, paragraph 10 k) 
As such a deviation, its use will be required to be accompanied by a 
statement disclosing and justifying the deviation. (DOE Order No. RA 
6120.2, paragraph 13.) Such justification must be included in the 
transmittal memorandum from the Secretary to FERC or in a footnote to 
the reports that accompany such transmittal.
    Response: All of the investments in the Ratesetting PRS are 
authorized power system facilities for which Congress has appropriated 
funds for FY 1993 construction, and which will be in service within the 
cost evaluation period. Therefore, Western believes it has complied 
with DOE Order No. RA 6120.2. The Engineering Ten-Year Plan was used to 
determine if the investments in the FY 1993 Budget were still planned 
to be in service within the cost evaluation period. The Engineering 
Ten-Year Plan was a better source of data to use in terms of timing of 
completion of construction activities and the dollars that will be 
spent in years 1994-98. The appropriated budget amounts for FY 1993 
were changed only to match the most current budget information. Western 
believes that the Engineering Ten-Year Plan was the best data available 
at the time.
    Comment: Reclamation should increase the rate for project use.
    Response: Reclamation is currently reviewing the accuracy of the 
project use rates. If it is determined that the project use rates 
require adjustment, Reclamation will take the necessary steps to 
implement a change in these rates. The resulting change, if any, will 
be reflected in a future PRS conducted by Western.
    Comment: Western continues to be out of compliance with DOE Order 
No. RA 6120.2 which requires audits at least once every 2 years.
    Response: Western is in compliance with DOE Order No. RA 6120.2 in 
that it has annual audits. Western has either had an annual 
consolidated Western-wide audit or project-specific audit which both 
meet the criteria of DOE Order No. RA 6120.2. Currently, P-DP is 
undergoing a project-specific audit.
    Comment: There is concern in justifying this rate increase in light 
of WAPA's own admission that the existing rate is adequate to fully 
recover costs and meet repayment requirements for at least the next 5 
years. The pinch-point methodology used in the PRS for determining the 
rates is doing the customers a disservice.
    Comment: The establishment of the current rate based upon 
anticipated revenue requirements in FY 2047 is unreasonable.
    Response: P-DP's PRSs are required to repay each dollar of 
investment with interest within a period not to exceed 50 years. The 
use of the pinch-point methodology and the longstanding practice of 
repaying investment with interest within 50 years are justified and 
identified in DOE Order No. RA 6120.2. Section 12 of the Order 
describes the guidelines for the cost recovery criteria which is what 
the pinch-point methodology accomplishes. The pinch-point in the 
Ratesetting PRS is FY 2047. This pinch-point is due to a required 
payment needed to fully repay an investment within a 50-year period.
    Comment: There is disagreement with Western's classification 
process for capitalizing versus expensing. O&M expense costs should be 
classified as a capital cost and amortized over the expected service 
life of the facility involved. Specifically, vehicle expenditures were 
classified as expense rather than capitalized.
    Response: Vehicle expenditures were expensed rather than 
capitalized and it is Western's policy to expense minor replacements 
($5,000 or less) and capitalize major replacements (over $5,000). 
However, the particular budget document that is being questioned 
contains a significant number of (i) expendable communication items and 
(ii) electrical test equipment, in addition to several vehicles. The 
service lives of the communication items and test equipment is 
sufficiently short enough to justify expensing the costs of said 
equipment. Due to the fact that only a small portion of the costs of 
the budget document were related to the purchase of vehicles, a 
decision was made to expense the entire budgeted amount.
    Comment: Customer feels Western should withdraw its proposal 
regarding the expansion of its area load control boundaries to the 
Basic Substation. They feel Western has no justification for this 
proposal and there are no benefits.
    Response: Western does not believe this comment pertains to, or has 
any impact on, the P-DP provisional rates. However, Western has 
withdrawn the proposal to expand Western's load control boundaries to 
Basic Substation.
    Comment: Western is accelerating repayments to periods far shorter 
than the average or expected service life of the facilities involved. 
Capital investments are being amortized over unduly short periods.
    Response: The PRS program is designed to solve at the lowest rate 
possible that is consistent with sound business principles. The PRS 
program is designed to calculate a rate over a 50-year period. However, 
the program will repay investment in a shorter period of time to 
minimize interest expense, providing revenue is available to accomplish 
this. If capital investment repayment was deferred, then interest 
expense would increase, which could result in a higher rate.
    Comment: P-DP has an additional 30 MW of firm capacity because 
Hoover is providing the P-DP spinning reserves. However, Western should 
not transfer revenue to the Hoover project with regard to spinning 
reserves.
    Response: Western has researched this matter thoroughly and can 
find no evidence that Hoover is providing spinning reserves to the P-
DP. Although the Consolidated Marketing Plan anticipated that an 
additional 30 MW of P-DP capacity would be available for sale as a 
result of consolidated operations within the Boulder City Area (now the 
Phoenix Area), spinning reserve requirements have not changed. The PAO 
operations department, in conjunction with a consultant on loan from 
MWD, is continuing to investigate this issue. Any identified benefits 
to the P-DP will be reflected in future PRSs.
    Comment: Customer objects to the continuance of Western's 1989 
decision to change the costs for using the Hoover-Basic and Hoover-
Mead-Basic transmission lines and Basic Substation from a facilities 
use charge to the postage-stamp rate for the entire P-DP transmission 
system.
    Western should revise its proposed P-DP rate adjustments in a 
manner that restores the Hoover-Basic and Hoover-Mead-Basic 
transmission lines and the Basic Substation to a facilities use charge 
which covers the actual costs associated with use of these facilities.
    Response: Western does not believe that this comment pertains to or 
impacts the P-DP provisional rates.
    Comment: The customers are concerned that they may be paying twice 
for the same service since Mead is already part of the P-DP. Western is 
already charging Edison $0.624/kW/year for use of the substation under 
their existing agreement.
    Response: Western has reviewed the provisions concerning the Mead 
facilities charges in the P-DP transmission agreements and has 
determined that there is no double accounting to the customers for the 
same capital facilities. In determining Mead facilities charges to 
Parker-Davis transmission customers, the costs of the Mead facilities, 
replacements, and O&M expenses are first allocated to the P-DP based 
upon the number of functions used. This allocation is further allocated 
based upon the transmission capacity as stated in the contracts.

Environmental Evaluation

    In compliance with the National Environmental Policy Act of 1969 
(NEPA) 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 the environmental assessment or EIS.

Executive Order 12866

    DOE has determined that this is not a significant regulatory action 
because it does not meet the criteria of Executive Order 12866, 58 FR 
51735. Western has an exemption from centralized regulatory review 
under Executive Order 12866; accordingly, no clearance of this notice 
by OMB is required.

Availability of Information

    Information regarding these P-DP rate adjustments, including PRSs, 
comments, letters, memorandums, and other supporting material made or 
kept by Western for the purpose of developing the P-DP power rates, is 
available for public review in the Phoenix Area Office, Western Area 
Power Administration, Office of the Assistant Area Manager for Power 
Marketing, 615 South 43rd Avenue, Phoenix, Arizona 85009-5313; Western 
Area Power Administration, Division of Marketing and Rates, 1627 Cole 
Boulevard, Golden, Colorado 80401-3398; and Western Area Power 
Administration, Office of the Assistant Administrator for Washington 
Liaison, Room 8G-061, Forrestal Building, 1000 Independence Avenue SW., 
Washington, DC 20585.

Submission to Federal Energy Regulatory Commission

    The P-DP rates herein confirmed, approved, and placed into effect 
on an interim basis, together with supporting documents, will be 
submitted to FERC for confirmation and approval on a final basis. 
Western understands that the effective date is less than 30 days after 
the Deputy Secretary places the provisional rates into effect on an 
interim basis. A waiver of Sec. 903.21(b) was requested to avoid 
financial difficulties, and I concur in that waiver.

Order

    In view of the foregoing and pursuant to the authority delegated to 
me by the Secretary of Energy, I confirm and approve on an interim 
basis, effective February 1, 1994, P-DP Rate Schedules PD-F4 for firm 
power, PD-FT4 for firm transmission, PD-NFT4 for nonfirm transmission, 
and PD-FCT4 for firm transmission service for SLCA/IP. The P-DP rate 
schedules shall remain in effect on an interim basis, pending FERC 
confirmation and approval of them or substitute rates on a final basis, 
through January 31, 1999 or until superseded.

    Issued in Washington, DC, January 6, 1994.
William H. White,
Deputy Secretary.

Rate Schedule INT-FT1

United States Department of Energy, Western Area Power 
Administration, Pacific Northwest-Pacific Southwest Intertie 
Project Schedule of Rates for Firm Transmission Service

Effective

    Step One: The first day of the first full billing period beginning 
on or after August 1, 1993.
    Step Two: The first day of the first full billing period beginning 
on or after October 1, 1995, and will remain in effect through July 31, 
1998, until superseded, whichever occurs first.

Available

    Within the marketing area served by the Pacific Northwest-Pacific 
Southwest Intertie Project.

Applicable

    To firm transmission service customers where capacity and energy 
are supplied to the Pacific Northwest-Pacific Southwest Intertie 
Project (AC Intertie) system at points of interconnection with other 
systems and transmitted and delivered, on a bidirectional basis, less 
losses, to points of delivery on the AC Intertie system specified in 
the service contract.

Character and Conditions of Service

    Alternating current at 60 Hertz, three-phase, delivered and metered 
at the voltages and points of delivery established by contract.

Rate

    Step One: Firm Transmission Service Charge: $4.46 per kilowatt per 
year for each kilowatt delivered at the point of delivery, as 
established by contract: payable monthly at the rate of $0.372 per 
kilowatt.
    Step Two: Firm Transmission Service Charge: $8.01 per kilowatt per 
year for each kilowatt delivered at the point of delivery, as 
established by contract: payable monthly at the rate of $0.6675 per 
kilowatt.

Adjustments

For Reactive Power

    None. There shall be no entitlement to transfer of reactive 
kilovolt-amperes at points of delivery, except when such transfers may 
be mutually agreed upon by contractor and contracting officer or their 
authorized representatives.

For Losses

    Capacity and energy losses incurred in connection with the 
transmission and delivery of capacity and energy under this rate 
schedule shall be supplied by the customer in accordance with the 
service contract.

Billing for Unauthorized Overruns

    For each billing period in which there is a contract violation 
involving an unauthorized overrun of the contractual firm power and/or 
energy obligation, such overrun shall be billed at 10 times the above 
rate.

Rate Schedule INT-NFT1

United States Department of Energy, Western Area Power 
Administration; Pacific Northwest-Pacific Southwest Intertie 
Project

Schedule of Rates for Nonfirm Transmission Service

Effective

    Step One: The first day of the first full billing period beginning 
on or after August 1, 1993.
    Step Two: The first day of the first full billing period beginning 
on or after October 1, 1995, and will remain in effect through July 31, 
1998, until superseded, whichever occurs first.

Available

    Within the marketing area served by the Pacific Northwest-Pacific 
Southwest Intertie Project.

Applicable

    To nonfirm transmission service customers where capacity and energy 
are supplied to the Pacific Northwest-Pacific Southwest Intertie 
Project (AC Intertie) system at points of interconnection with other 
systems and transmitted and delivered, on a bidirectional basis, less 
losses, to points of delivery on the AC Intertie system established by 
contract.

Character and Conditions of Service

    Alternating current at 60 Hertz, three-phase, delivered and metered 
at the voltages and points of delivery established by contract.

Rate

    Step One: Nonfirm Transmission Service Charge: 1.00 mills per 
kilowatthour of the scheduled or delivered kilowatthours at the point 
of delivery, established by contract: payable monthly.
    Step Two: Nonfirm Transmission Service Charge: 1.52 mills per 
kilowatthour of the scheduled or delivered kilowatthours at the point 
of delivery, established by contract: payable monthly.

Adjustments

For Reactive Power

    None. There shall be no entitlement to transfer of reactive 
kilovolt-amperes at points of delivery, except when such transfers may 
be mutually agreed upon by contractor and contracting officer or their 
authorized representatives.

For Losses

    Capacity and energy losses incurred in connection with the 
transmission and delivery of capacity and energy under this rate 
schedule shall be supplied by the customer in accordance with the 
service contract.

[FR Doc. 94-2730 Filed 2-4-94; 8:45 am]
BILLING CODE 6450-01-P