[Federal Register Volume 60, Number 200 (Tuesday, October 17, 1995)]
[Notices]
[Pages 53778-53785]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 95-25686]



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DEPARTMENT OF ENERGY
Western Area Power Administration


Parker-Davis Project--Notice of Rate Order No. WAPA-68

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of Rate Order--Parker-Davis Project Firm Electric 
Service Rate and Firm and Non-Firm Transmission 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-68 
and Rate Schedules PD-F5, PD-FT5, PD-NFT5, and PD-FCT5 placing 
decreased firm power rates for capacity and energy and decreased firm 
and non-firm transmission rates from the Parker-Davis Project (P-DP) of 
the Western Area Power Administration (Western) into effect on an 
interim basis. The interim rates, called the provisional 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, or until they are replaced by other rates.
    Western is requesting approval to place into effect a rate decrease 
in the firm power rates for capacity and energy and a rate decrease for 
firm and nonfirm transmission service from the P-DP. Four major changes 
are affecting the rates for the P-DP system
    The first change is in the costs apportionment study. This change 
was suggested by the P-DP customers and was a collaborative effort 
between all of Western's P-DP customers, Western and the Bureau of 
Reclamation (Reclamation). The new costs apportionment study more 
accurately allocates the P-DP's total power related costs and revenue 
between generation and transmission. In the previous 

[[Page 53779]]
ratesetting study for Step Two rates, the apportionment percentages 
between generation and transmission were approximately 26 percent and 
74 percent, respectively. Based upon a reallocation of these costs, the 
appointment percentages between generation and transmission are 
approximately 16 percent and 84 percent, respectively.
    The second change concerns the ratesetting methodology. This change 
has also been made in response to questions and concerns voiced by 
Western's P-DP customers. Previously, rates were set using the 
traditional pinch-point methodology, where 50 years of data was 
analyzed and rates were based on the year in which the revenue 
requirement was the highest. Under the proposed methodology, revenue 
requirements are determined for the next five years. In addition, a 
compound interest amortization schedule is prepared for all 
investments, including replacements, thus ensuring project repayment. 
By October 1 of each year, new rates for the following five year period 
will be determined and implemented.
    The third change concerns the determination of interest offsets. An 
interest offset is a credit that is made toward interest expense. 
Western has decided to handle interest offsets consistently with the 
other Federal power marketing administrations. The main difference 
between the new method and the old method is that the old method 
calculated interest offsets on only the principal that was repaid in 
the current year. The new method calculates interest offsets on both 
principal and interest for the current year.
    The final change is in the area of cost containment. Western and 
its customers have participated in many collaborative, or partnership, 
efforts since the last P-DP rate process. Western has significantly 
increased its customer's input into its engineering and future 
construction program, its maintenance activities, and in its financial 
planning and budget planning activities. This collaborative effort has 
resulted in a significant decrease in both future operation and 
maintenance expenses and capital expenses.
    A comparison of existing and provisional rates follows:

                       Comparison of Existing and Provisional Power and Transmission Rates                      
----------------------------------------------------------------------------------------------------------------
                                  Step 2 of the existing rates                                                  
                                October 1, 1995, through January  Proposed rates October 1, 1995\1\    Percent  
                                            31, 1999                                                    change  
----------------------------------------------------------------------------------------------------------------
Composite Rate\2\ (mills/kWh)  12.01............................  6.33.............................       -47.29
Firm Capacity Charge ($/kW/    $2.63............................  $1.92............................       -27.00
 month) PD-F5.                                                                                                  
Firm Energy Charge (mills/     6.01.............................  1.95.............................       -67.55
 kWh) PD-F5.                                                                                                    
Firm Transmission Service ($/  $12.55...........................  $11.51...........................        -8.29
 kW/year) PD-FT5.                                                                                               
Nonfirm Transmission Service   2.39.............................  2.19.............................        -8.37
 (mills/kWh) PD-NFT5.                                                                                           
Transmission Service for SLCA/ $6.27 per kW-Season..............  $5.76 per kW-Season..............        -8.13
 IP PD-FCT5.                                                                                                    
----------------------------------------------------------------------------------------------------------------
\1\A new rate will be determined each year on September 1, based upon the proposed new ratesetting methodology. 
  These rates represent FY 1996 only.                                                                           
\2\The Composite Rate is the total of the Firm Capacity Charge, the Firm Energy Charge and the Firm Transmission
  Service, all expressed on a mills/kWh basis.                                                                  

DATES: Rate Schedules PD-F5, PD-FT5, PD-FCT5, and PD-NFT5 will be 
placed into effect on an interim basis on the first day of the first 
full billing period beginning on or after October 1, 1995, and will be 
in effect until FERC confirms, approves, and places the rate schedules 
into effect on a final basis for a five year period, or until the rate 
schedules are superseded.

FOR FURTHER INFORMATION CONTACT:

Mr. J. Tyler Carlson, Area Manager, Phoenix Area Office, Western Area 
Power Administration, P.O Box 6457, Phoenix, AZ 85005-6457, (602) 352-
2453
Ms. Deborah M. Linke, Acting Director, Division of Power Marketing, 
Western Area Power Administration, P.O Box 3402, Golden CO 80401-0098, 
(303) 275-1610
Mr. Joel K. Bladow, Assistant Administrator for Washington Liaison, 
Western Area Power Administration, Room 8G-027, 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 (Secretary) 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 37835).
    These power rates are established pursuant to section 302(a) of the 
Department of Energy (DOE) Organization Act, 42 U.S.C. 7152(a), through 
which the power marketing functions of the Secretary of the Interior 
and Reclamation under the Reclamation Act of 1902, 43 U.S.C. 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. 485h(c), and other acts specifically applicable to the project 
system involved, were transferred to and vested in the Secretary.
    Most of the comments received at the public meetings and in 
correspondence dealt with purchase power costs, comparability issues 
with the recently announced FERC notice of proposed rulemaking 
concerning open access non-discriminatory transmission service, the new 
rate methodology and Reclamation's working capital improvement process.
    Rate Order No. WAPA-68, confirming, approving, and placing the 
proposed P-DP rate adjustments into effect on an interim basis, is 
issued, and the new Rate Schedules PD-F5, PD-FT5, PD-FCT5, and PD-NFT5 
will be submitted promptly to FERC for confirmation and approval on a 
final basis.


[[Page 53780]]

    Issued in Washington, DC, September 29, 1995.
Charles B. Curtis,
Deputy Secretary.

Department of Energy--Deputy Secretary

    In the matter of: Western Area Power Administration, Rate 
Adjustment for Parker-Davis Project. Rate Order No. WAPA-68.

Order Confirming, Approving, and Placing the Parker-Davis Project Firm 
Power Service Rate, Firm Transmission Service Rate, Nonfirm 
Transmission Service Rate and Transmission Service for the Salt Lake 
City Area/Integrated Projects Into Effect on an Interim Basis

October 1, 1995.
    These power rates are established pursuant to section 302(a) of the 
Department of Energy (DOE) Organization Act, 42 U.S.C. 7152(a), through 
which 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. 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. 485h(c), and other acts specifically 
applicable to the project system involved were transferred to and 
vested in the Secretary of Energy (Secretary).
    By Amendment No. 3 to Delegation Order No. 0204-108, published 
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:

$/kW/month: Monthly charge for capacity (usage--$ per kilowatt per 
month).
Costs Apportionment Study: A study which allocates P-DP's total costs 
and other revenue between generation and transmission.
CROD: Contract rate of delivery.
Customer Brochure: A document prepared for public distribution 
explaining the background of the rate proposal contained in this rate 
order.
DOE: Department of Energy.
DOE Order RA 6120.2: An order dealing with power marketing 
administration financial reporting.
EA: Environmental assessment.
EIS: Environmental impact statement.
FERC: Federal Energy Regulatory Commission.
FY: Fiscal year.
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.
kWh: Kilowatthour.
mills/kWh: Mills per kilowatthour.
MW: Megawatt.
NEPA: National Environmental Policy Act of 1969.
NOPR: Notice of Proposed Rulemaking.
O&M: Operation and maintenance.
P-DP: Parker-Davis Project.
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.
PAO: Western's Phoenix Area Office.
PMA: Power marketing administration.
Proposed Rate: A rate revision that the Administrator of Western 
recommends to the Deputy Secretary.
Provisional Rate: A rate which has been confirmed, approved, and placed 
into effect on an interim basis by the Deputy Secretary.
PRS: Power repayment study.
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.
SLCA/IP: Salt Lake City Area/Integrated Projects.
Western: Western Area Power Administration, U.S. Department of Energy.

Effective Date

    The new rates and rate methodology will become effective on an 
interim basis on the first day of the first full billing period 
beginning on or after October 1, 1995, and will be in effect pending 
FERC's approval of them or substitute rates on a final basis for a five 
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 firm power rate, firm transmission 
rate, and nonfirm transmission rate. The provisional firm power rate, 
firm transmission rate, and nonfirm transmission rate will cause more 
than a 1 percent change in total P-DP power 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 a 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. Discussion of the proposed rate adjustment was initiated on 
February 16, 1995, when a letter announcing an informal customer 
meeting was mailed to all firm power customers, firm and nonfirm 
transmission customers, and other interested parties. The informal 
customer meeting was held on February 22, 1995, in Phoenix, Arizona. At 
this informal meeting, Western and Reclamation Representatives 
explained the need for the rate adjustments and answered questions for 
those attending.
    2. A Federal Register notice was published on March 21, 1995 (60 FR 
14935), officially announcing the proposed firm power rate, firm 
transmission rate, and nonfirm transmission rate adjustment; initiating 
the public consultation and comment period; announcing the public 
information and public comment forums, and presenting procedures for 
public participation.
    3. On March 29, 1995, letters were mailed from PAO to all P-DP firm 
power, firm transmission, and nonfirm transmission customers and other 
interested parties, providing a copy of the P-DP Rate Brochure dated 
March 1995. The Rate Brochure also included a copy of the Federal 
Register notice of March 21, 1995.
    4. At the public information forum on April 5, 1995, Western and 
Reclamation representatives explained the need for the rate adjustments 
in greater detail and answered additional questions.
    5. The public comment forum was held on May 15, 1995, to give the 
customers and interested parties an opportunity to comment for the 
record. Five persons, representing customers and customer groups, made 
oral comments.
    6. On June 22, 1995, a letter was mailed to all P-DP customers and 
interested parties with copies of an updated PRS and rate design 
spreadsheets.

[[Page 53781]]

    7. A Federal Register notice was published on July 6, 1995 (60 FR 
35199), extending the consultation and comment period until July 12, 
1995.
    8. Eight comment letters were received during the 114-day 
consultation and comment period which ended July 12, 1995. All formally 
submitted comments have been considered in the preparation of this rate 
order.

Project History

    The Parker Dam Power Project was authorized by section 2 of the 
Rivers and Harbors Act of August 30, 1935 (49 Stat. 1039). 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. 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).
    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, 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 
the Metropolitan Water District of Southern California (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 the state of Arizona. Reservoir 
operation is limited to minor storage fluctuations. The dam provides a 
head of approximately 75 feet for Parker Powerplant. Reclamation began 
operation of 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. MWD is 
entitled, under current contract, to one-half of the net energy 
generated by Parker Powerplant at any given time.
    Davis Dam, which created Lake Mohave, provides regulation, both 
hourly and seasonally, of 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 1974-1978, the generator nameplate 
capacity was increased to 240,000 kW by rewinding the generator 
stators.
    All facilities of the P-DP were operated and maintained by 
Reclamation until the formation of the DOE pursuant to the DOE 
Organization Act (DOE Act), 42 U.S.C. Sections 7101 et seq., enacted by 
Congress on August 4, 1977. Pursuant to section 302 of the DOE Act (42 
U.S.C. 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 the DOE. The responsibility for operation and 
maintenance of the dams and powerplants remains with Reclamation.

Power Repayment Studies

    PRS's are prepared each fiscal year 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 RA 6120.2, 
section 12b, requires that:
    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 Rates

    A comparison of existing and provisional rates follows:

                       Comparison of Existing and Provisional Power and Transmission Rates                      
----------------------------------------------------------------------------------------------------------------
                                  Step 2 of the existing rates                                                  
                                October 1, 1995, through January  Proposed rates October 1, 1995\1\    Percent  
                                            31, 1999                                                    change  
----------------------------------------------------------------------------------------------------------------
Composite Rate\2\ (mills/kWh)  12.01............................  6.33.............................       -47.29
Firm Capacity Charge ($/kW/    $2.63............................  $1.92............................       -27.00
 month) PD-F5.                                                                                                  
Firm Energy Charge (mills/     6.01.............................  1.95.............................       -67.55
 kWh) PD-F5.                                                                                                    
Firm Transmission Service ($/  $12.55...........................  $11.51...........................        -8.29
 kW/year) PD-FT5.                                                                                               
Nonfirm Transmission Service   2.39.............................  2.19.............................        -8.37
 (mills/kWh) PD-NFT5.                                                                                           
Transmission Service for SLCA/ $6.27 per kW/season..............  $5.76 per kW/season..............        -8.13
 IP PD-FCT5.                                                                                                    
----------------------------------------------------------------------------------------------------------------
\1\A new rate will be determined each year on September 1, based upon the proposed new ratesetting methodology. 
  These rates represent FY 1996 only.                                                                           
\2\The Composite Rate is the total of the Firm Capacity Charge, the Firm Energy Charge and the Firm Transmission
  Service, all expressed on a mills/kWh basis.                                                                  

Certification of Rate

    Western's Administrator has certified that the P-DP firm power 
rate, firm transmission rate, nonfirm transmission rate, and the 
transmission service for SLCA/IP rate, 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

    Western is requesting approval to place into effect a rate decrease 
in the 

[[Page 53782]]
firm power rates for capacity and energy and a rate decrease for firm 
and nonfirm transmission service from the P-DP of the Western Area 
Power Administration on an interim basis. Four major changes are 
affecting the rates for the Parker-Davis system.
    The first change is in the costs apportionment study. This change 
was suggested by the P-DP customers and was a collaborative effort 
between all of Western's P-DP customers, Western and Reclamation. Since 
the last rate adjustment process, Western has worked with the customers 
to develop a revised costs apportionment study which can be described 
in four steps.
    1. All costs, including Western's O&M expenses, Reclamation 
expenses, purchase power costs, multi-project costs associated with 
Mead Service Center, interest expenses, and principal payments were 
allocated to either generation or transmission. Each component was 
allocated based on whether it was directly related to generation or 
transmission. If a component was related to both, a customer allocation 
factor based on the number of customers was used to separate costs 
between generation and transmission.
    2. All revenues, including nonfirm transmission, nonfirm energy, 
fuel replacement, spinning reserves, facility use charges, and multi-
project revenues associated with SCADA and the Phoenix Service Center 
were allocated to either generation or transmission. Each component was 
allocated based on whether it was directly related to generation or 
transmission. If a component was related to both, a customer allocation 
factor was used to separate other sources of revenues between 
generation and transmission.
    3. Project use costs for both generation and transmission were 
compared to the anticipated revenue of $1.2 million. The difference 
between the project use costs and the anticipated revenues was 
allocated to the generation and transmission customers. This allocation 
was based on the ratio of project use generation costs to project use 
transmission costs.
    4. Final percentages of costs associated with generation and costs 
associated with transmission were derived.
    The new costs apportionment study more accurately allocates the P-
DP's total power related costs and revenue between generation and 
transmission. In the previous ratesetting study for Step Two rates, the 
apportionment percentages between generation and transmission were 
approximately 26 percent and 74 percent, respectively. Based upon a 
reallocation of these costs, the new apportionment percentages between 
generation and transmission are approximately 16 percent and 84 
percent, respectively.
    The second change concerns the ratesetting methodology. This change 
has also been made in response to questions and concerns voiced by 
Western's P-DP customers. Previously, rates were set using the 
traditional pinch-point methodology, where 50 years of data was 
analyzed and rates were based on the year in which the revenue 
requirement was the highest. Under the proposed methodology, revenue 
requirements are determined for the next five years. In addition, a 
compound interest amortization schedule is prepared for all 
investments, including replacements, thus ensuring project repayment. 
By October 1 of each year, new rates for the following five year period 
will be determined and implemented.
    Under the previous pinch-point methodology, 50 years of data were 
analyzed and the rate was based on the year in which the highest 
revenue requirement was encountered. This methodology used a priority 
of repayment which first applied annual revenues to operation and 
maintenance expenses, purchased power expenses, interest, and then to 
required annual principal payments. Any excess annual revenue was then 
applied toward principal owed to the Federal Treasury. Under the new 
repayment methodology, Western first determines an amortization 
schedule of all existing and future investments. This includes both a 
principal component and an interest component. Western then adds this 
annual amortization amount to operation and maintenance expenses, 
purchase power expenses, and other annual expenses to determine the 
total annual revenue requirements over the next five years. An average 
revenue requirement and an average rate are than calculated for the 
five year period. Revenues collected that are in excess of the annual 
revenue requirement are carried forward to the next year and are 
utilized to cover revenue shortfalls in future years. This new 
methodology, while relying on a five year rate setting period instead 
of 50 years, provides for guaranteed payment of all costs within the 
five year rate setting window and establishes a guaranteed methodology 
concerning repayment of principal, thus ensuring total repayment of the 
project within its prescribed time period.
    RA 6120.2 states that revenues remaining after paying for annual 
expenses shall be used to repay the Federal investment. Under the new 
ratesetting methodology, repayment of the Federal investment will 
become a component of the total annual expenses and will be made on an 
annual basis through a compound interest amortization payment. Any 
excess revenues remaining after the payment of total annual expenses 
will be carried forward to the following operating year to be applied 
toward annual expenses.
    The third change concerns the determination of interest offsets. An 
interest offset is a credit that is made toward interest expense. 
Western has decided to handle interest offsets consistent with the 
other Federal power marketing agencies. The main difference between the 
new method and the old method is that the old method calculated 
interest offsets on only the principal that was repaid in the current 
year. The new method calculates interest offsets on both principal and 
interest for the current year.
    The final change is in the area of cost containment. Western and 
its customers have participated in many collaborative, or partnership, 
efforts since the last P-DP rate process. Western has significantly 
increased its customer's input into its engineering and future 
construction program, its maintenance activities, and in its financial 
planning and budget planning activities. This collaborative effort has 
resulted in a significant decrease in both future operation and 
maintenance expenses and capital expenses.
    Since the last P-DP rate process was concluded, Western and the 
customers have worked quite closely in a partnership process to 
implement a coordinated 10-year engineering and construction plan 
process. This process annually generates a 10-Year Engineering and 
Construction plan, which is issued in October of each year. This 
process is also integrated with Western's rates and budgeting processes 
to (1) provide certainty to the customers that all of Western's 
processes are operating from the same financial base and (2) provide 
the customers with the maximum input possible into the financial 
decisions that are reflected in the rates paid by the customers. This 
process has resulted in considerable changes both in the way Western 
does business and in the amount of future expenditures Western will be 
committing on behalf of its customers.

Power Sales Revenue Requirements

    A comparison of the power sales revenue requirements estimated for 
1996 and the existing 1996 power sales revenue requirements are noted 
in the table below.

                                                                                                                

[[Page 53783]]
------------------------------------------------------------------------
                                            Estimated 1996 revenue      
                                     -----------------------------------
                                          Existing          Proposed    
------------------------------------------------------------------------
Power Sales Revenue Requirements....    \1\$42,011,732    \2\$28,521,763
------------------------------------------------------------------------
\1\From the Parker-Davis Project Rate Design Worksheet for WAPA-55, Step
  2.                                                                    
\2\From the Parker-Davis Project Rate Design Worksheet for WAPA-68.     


    The rate decrease satisfies the cost-recovery criteria set forth in 
DOE Order RA 6120.2.

Statement of Revenue and Related Expenses

    The following table provides a summary of revenue and expense data 
through the 5-year Provisional Rates approval period.

   Parker-Davis Project Comparison of 5-Year Rate Period Revenues and   
                                Expenses                                
                        [In thousands of dollars]                       
------------------------------------------------------------------------
                                                  Current               
                                   Provisional     step 2               
                                   ratesetting    proposed              
                                    (FY 1996)     rate (FY    Difference
                                    PRS 1996-    1995) PRS              
                                       2000      1996-2000              
------------------------------------------------------------------------
Total Revenues\1\................      180,212      210,401       30,189
Revenue Distribution:                                                   
    O&M..........................      114,874      123,095        8,221
    Purchased Power..............        4,500        1,400       -3,100
    Other........................        1,017        2,891        1,874
    Interest.....................       56,452       66,130        9,678
    Investment Repayment.........        3,014       13,113       10,099
    Capitalized Expenses.........          355        3,772        3,417
                                  --------------------------------------
      Total......................      180,212      210,401       30,189
------------------------------------------------------------------------
\1\Total Revenues includes revenues from all sources. Total Revenues for
  the Provisional ratesetting PRS also includes excess revenues from the
  previous year.                                                        

Basis for Rate Development

    The rates were designed using a cost apportionment study. The study 
was based upon the separation of costs between generation and 
transmission. As a result of the study, 84 percent of the P-DP costs 
are to be recovered from the firm transmission customers, while the 
remaining 16 percent of the costs are to be recovered from firm power 
customers. The rate design consists of five steps.
    1. Required revenue is derived in the proposed PRS for the period 
1996 through 2000.
    2. The percentages from the Costs Apportionment Study for 
generation and transmission are applied to the total revenue 
requirements in step one above. This determines the required revenue 
for generation and the required revenue for the transmission system.
    3. The firm transmission rate is developed by dividing the required 
revenue for transmission by the total transmission sales. Total 
transmission sales includes firm transmission service and firm electric 
service.
    4. The transmission rate is applied to the sales for firm 
transmission service to determine transmission revenues.
    5. The demand and energy components of the power rate are then 
calculated. The demand component is calculated by (i) first multiplying 
the firm transmission rate by the maximum firm electric service kW 
sales, (ii) adding 50 percent of the required revenue for generation 
and then (iii) dividing this total revenue requirement by the average 
firm electric service kW sales.
    The energy component is determined by dividing 50 percent of the 
generation revenue requirements by the total firm electric service kWh 
sales.
    The composite rate is determined by adding the revenue requirements 
associated with demand and the revenue requirements associated with 
energy and dividing by the total firm electric kWh sales.
    The SLCA/IP rate is determined by dividing the firm transmission 
service rate in half, to determine the seasonal rate.

Comments

    During the 114-day comment period. Western received eight written 
comments either requesting additional information or commenting on the 
rate adjustment. In addition, five persons provided oral comments 
during the May 15, 1995, public comment forum. All comments were 
reviewed and considered in the preparation of this rate order.
    Written comments were received from the following sources:

Arizona Public Service Company (Arizona)
Salt River Project (Arizona)
Maricopa Water District (Arizona)
Ak-Chin Indian Community (Arizona)
Irrigation & Electrical Districts Association of Arizona (Arizona)
Tonopah Irrigation District (Arizona)
Overton Power District No. 5, Valley Electric Association, Inc. 
(Nevada)
Arizona Power Authority--R.W. Beck (Arizona)

    Representatives of the following organizations made oral comments:

Overton Power District No. 5, Valley Electric Association, Inc. 
(Nevada)
Arizona Power Authority (Arizona) (two commenters)
Salt River Project (Arizona)
Irrigation & Electric District Association of Arizona (Arizona)

    Most of the comments received at the public meetings and in 
correspondence dealt with purchase power costs, comparability issues 
with the recently announced FERC notice of proposed rulemaking 
concerning open access non-discriminatory transmission service, new 
rate methodology, and Reclamation's working capital improvement 
process.

[[Page 53784]]

    Issue: Some customers expressed concern about purchase power costs 
that have been incurred in the past, especially in unusual flood years, 
such as occurred in 1993. Western was forced into a position of buying 
power to replace lost generation when the customers did not need 
replacement power. How do we handle this hydrologic condition so it 
doesn't happen again?
    Response: Western shares the customers' concern that this 
hydrologic condition could occur again. In the near future, Western 
will set up a working group to examine how to keep purchase powers 
costs from occurring under these particular conditions. Western looks 
forward to working with its customers on this issue.
    Issue: Customers would like Western to determine what would be 
required of Western should FERC finalize its notice of proposed 
rulemaking (NOPR) on the comparability issue.
    Response: Presently, Western has several working groups set up to 
determine what would be required of Western should the FERC NOPR become 
final. This is a Western-wide issue. Once the requirements on 
comparability are determined and Western determines how it will 
voluntarily adhere to such requirements, such information will be made 
available to all customers and interested parties.
    Issue: Customers would like Reclamation to continue to commit to 
enter into a 10-year planning process related to costs and expenditures 
of the Parker-Davis Project.
    Response: Reclamation has verbally committed to continue to work 
with the customers on a 10-year planning process related to its 
operations and maintenance expenses.
    Issue: The customers support the compound interest amortization 
process and commend Western for implementation of this item in the PRS.
    Response: Western acknowledges the customer's support and looks 
forward to working with customers on other process improvement issues.
    Issue: One transmission customer requested that the 11.5 percent 
increase for the firm transmission rate be phased in using a two-step 
process.
    Response: Western received only one comment pertaining to phasing 
in the firm transmission rate. While the provisional firm transmission 
rate of $11.51/kW-yr is 10.67 percent higher than the existing Step 1 
rate of $10.40/kW-yr, it is 8.29 percent lower than the existing Step 2 
rate previously proposed to go into effect October 1, 1995. Western 
believes that a phase in of the rate will not be necessary.

Environmental Evaluation

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

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 Office of Management and Budget is required.

Availability of Information

    Information regarding this rate adjustment, including PRSs, 
comments, letters, memorandums, and other supporting material made by 
or kept by Western for the purpose of developing the 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; Western Area 
Power Administration, Division of Power Marketing, 1627 Cole Boulevard, 
Golden, Colorado 80401; and Western Area Power Administration, Office 
of the Assistant Administrator for Washington Liaison, Room 8G-027, 
Forrestal Building, 1000 Independence Avenue SW., Washington, DC 20585.

Submission to Federal Energy Regulatory Commission

    The rate 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.

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 October 1, 1995, Rate Schedules PD-F4, PD-FT4, PD-
FCT5, and PD-NFT5 for the P-DP. The rate schedule shall remain in 
effect on an interim basis, pending the Federal Energy Regulatory 
Commission confirmation and approval of it or a substitute rate on a 
final basis, through September 30, 2000.

    Issued in Washington, DC, September 29, 1995.
Charles B. Curtis,
Deputy Secretary.

Department of Energy--Western Area Power Administration; Parker-Davis 
Project

Schedule of Rates for Wholesale Firm Power Service

[Rate Schedule PD-F5 Supersedes Schedule PD-F4]

    Effective: The first day of the first full billing period beginning 
on or after October 1, 1995, and remaining in effect through September 
30, 2000, or until superseded, whichever occurs first.
    Available: In the marketing area serviced by the Parker-Davis 
Project (P-DP).
    Applicable: To the wholesale power customers for firm power service 
supplied through one meter at one point of delivery, unless otherwise 
provided by contract.
    Character and Conditions of Service: Alternating current at 60 
hertz, three-phase, delivered and metered at the voltages and points 
established by contract.
    Monthly Rate: October 1, 1995:
    Demand Charge: $1.92 per kilowatt of billing demand.
    Energy Charge: 1.95 mills per kilowatthour of use.
    Billing Demand: The billing demand will be the greater of (1) the 
highest 30-minute integrated demand measured during the month up to, 
but not in excess of, the delivery obligation under the power sales 
contract, or (2) the contract rate of delivery.
    October 1, 1996, through September 20, 2000:
    By October 1 of each year, a new rate for the following 5-year 
period will be determined and implemented as described in the rate 
design section of the rate order WAPA-68.
    Billing for Unauthorized Overruns: For each billing period in which 
there is a contract violation involving an unauthorized overrun of the 
contractual firm capacity and/or energy obligations, such overruns 
shall be billed at 10 times the above rate.
    For Transformer Losses: If delivery is made at transmission voltage 
but metered on the low-voltage side of the substation, the meter 
readings will be increased to compensate for transformer losses as 
provided for in the contract.
    For Power Factor: None. The customer will normally be required to 
maintain a power factor at all points of measurement between 95-percent 
lagging and 95-percent leading.

[[Page 53785]]


Department of Energy--Western Area Power Administration; Parker-Davis 
Project

[Rate Schedule PD-FT5 (Supersedes Schedule PD-FT4)]

Schedule of Rate for Firm Transmission Service

    Effective: The first day of the first full billing period beginning 
October 1, 1995, and remaining in effect through September 30, 2000, or 
until superseded, whichever occurs first.
    Available: Within the marketing area served by the Parker-Davis 
Project (P-DP).
    Applicable: To firm transmission service customers where capacity 
and energy are supplied to the P-DP system at points of interconnection 
with other systems and transmitted and delivered, less losses, to 
points of delivery on the P-DP 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 
established by contract.
    Monthly Rate: October 1, 1995:
    Transmission Service Charge: $11.51 per kilowatt per year for each 
kilowatt at the point of delivery, established by contract, payable 
monthly at the rate of $0.96 per kilowatt.
    October 1, 1996, through September 30, 2000:
    By October 1 of each year, a new rate for the following 5-year 
period will be determined and implemented as discussed in the rate 
design section of the rate order WAPA-68.
    For Reactive Power: None. There shall be no entitlement to transfer 
of reactive kilovolt-amperes at delivery points, except when such 
transfer 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 power 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 obligations, such overrun shall be 
billed at 10 time the above rate.

Department of Energy--Western Area Power Administration; Parker-Davis 
Project

[Rate Schedule PD-FCT5 (Supersedes Schedule PD-FCT4)]

Schedule of Rate for Firm Transmission Service of Salt Lake City Area 
Integrated Projects Power

    Effective: The first day of the first full billing period beginning 
on or after October 1, 1995, and remaining in effect through September 
30, 2000, or until superseded, whichever occurs first.
    Available: Within the marketing area served by the Parker-Davis 
Project (P-DP) transmission facilities.
    Applicable: To Salt Lake City Area/Integrated Projects (SLCA/IP) 
Southern Division Customers where SLCA/IP capacity and energy are 
supplied to the P-DP system by the Colorado River Storage Project 
(CRSP) at points of interconnection with the CRSP system and for 
transmission and delivery on a unidirectional basis, less losses, to 
Southern Division customers at points of delivery on the P-DP 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.
    Monthly Rate: October 1, 1995:
    Transmission Service Charge: $5.76 per kilowatt per season for each 
kilowatt at the point of deliver, established by contract.
    October 1, 1996, through September 30, 2000:
    By October 1 of each year, a new rate for the following 5-year 
period will be determined and implemented as discussed in the rate 
design section of the rate order WAPA-68.
    For Reactive Power: None. There shall be no entitlement to transfer 
of reactive kilovolt-amperes at delivery points, 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 power 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 obligations, such overrun shall be 
billed at 10 times that above rate.

Department of Energy--Western Area Power Administration; Parker-Davis 
Project

[Rate Schedule PD-NFT5 (Supersedes Schedule PD-NFT4]

Schedule of Rate for Nonfirm Transmission Service

    Effective: The first day of the first full billing period beginning 
on or after October 1, 1995, and remaining in effect through September 
30, 2000, or until superseded, whichever occurs first.
    Available: Within the marketing area serviced by the Parker-Davis 
Project (P-DP) transmission facilities.
    Applicable: To nonfirm transmission service customers where 
capacity and energy are supplied to the P-DP system at points of 
interconnection with other systems, transmitted subject to the 
availability of the transmission capacity, and delivered on a 
unidirectional basis, less losses, to points of delivery on the P-DP 
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.
    Monthly Rate: October 1, 1995:
    Nonfirm Transmission Service Charge: 2.19 mills per kilowatthour of 
scheduled or delivered kilowatthours at point of delivery, established 
by contract, payable monthly.
    October 1, 1996, through September 30, 2000:
    By October 1 of each year, a new rate for the following 5-year 
period will be determined and implemented as discussed in the rate 
design section of the rate order WAPA-68.
    For Reactive Power: None. There shall be no entitlement to transfer 
of reactive kilovolt-amperes at delivery points, 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 power and energy under this rate 
schedule shall be supplied by the customer in accordance with the 
service contract.

[FR Doc. 95-25686 Filed 10-16-95; 8:45 am]
BILLING CODE 6450-01-M