94-2730. Parker-Davis Project Notice of Rate Order No. WAPA-55  

  • [Federal Register Volume 59, Number 25 (Monday, February 7, 1994)]
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    [Page 0]
    From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
    [FR Doc No: 94-2730]
    
    
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    [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    effect on a final basis for a 5-year period or until superseded.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
    
    
    

Document Information

Effective Date:
2/1/1994
Published:
02/07/1994
Department:
Western Area Power Administration
Entry Type:
Uncategorized Document
Action:
Notice of Rate Order--Parker-Davis Project (P-DP) Firm Power Rate and Firm and Nonfirm Transmission Service Rate Adjustments.
Document Number:
94-2730
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.
Pages:
0-0 (1 pages)
Docket Numbers:
Federal Register: February 7, 1994