Federal Register, Volume 60 Issue 200 (Tuesday, October 17, 1995)

[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]

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

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