Parker-Davis Project Notice of Rate Order No. WAPA-55
Federal RegisterFeb 7, 1994
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DEPARTMENT OF ENERGY
Western Area Power Administration
Parker-Davis Project Notice of Rate Order No. WAPA-55
AGENCY: Western Area Power Administration, DOE.
ACTION: Notice of Rate Order--Parker-Davis Project (P-DP) Firm Power
Rate and Firm and Nonfirm Transmission Service Rate Adjustments.
-----------------------------------------------------------------------
SUMMARY: Notice is given of the confirmation and approval by the Deputy
Secretary of the Department of Energy (DOE) of Rate Order No. WAPA-55
placing the proposed rate schedules--firm power PD-F4, firm
transmission service PD-FT4, nonfirm transmission service PD-NFT4, and
firm transmission service for Salt Lake City Area/Integrated Projects
(SLCA/IP) PD-FCT4--for the P-DP of the Western Area Power
Administration (Western) into effect on an interim basis. These
proposed P-DP rates, hereafter called the provisional P-DP rates, will
remain in effect on an interim basis until the Federal Energy
Regulatory Commission (FERC) confirms, approves, and places them into
effect on a final basis for a 5-year period or until superseded.
The Deputy Secretary, DOE, approved the existing P-DP rate
schedules PD-F3, PD-FCT3, and PF-NFT3 by Rate Order No. WAPA-48 on an
interim basis, effective on October 1, 1990 (55 FR 36887, September 7,
1990). FERC approved the P-DP rate schedules on a final basis through
September 30, 1992, by Order dated November 15, 1990 (53 FERC Par.
62,157).
The Assistant Secretary for Conservation and Renewable Energy on
August 19, 1992 by Rate Order No. WAPA-57, extended these rate
schedules for not more than one year (57 FR 39400, August 31, 1992).
The Acting Assistant Secretary for Energy Efficiency and Renewable
Energy on September 29, 1993, by Rate Order No. WAPA-64, further
extended these rate schedules through March 31, 1994 (58 FR 50917;
September 29, 1993).
Neither of said WAPA Rate Orders, 57 or 64 were submitted to FERC
for its concurrence, inasmuch as these orders were in the nature of
temporary extensions of existing rates, pending the development of long
term rates, so that FERC approval would have been premature. In any
event, rates of such nature need not be approved by FERC, as specified
in existing regulations, 10 CFR 902.23(b).
Western is proposing to implement a two-step process for the
provisional P-DP rates for firm power and firm and nonfirm transmission
service. Step one of the provisional P-DP rates will become effective
February 1, 1994, and step two of the provisional P-DP rates will
become effective October 1, 1995.
Step one of the provisional P-DP rates consists of an energy rate
of 5.79 mills per kilowatthour (mills/kWh) and a capacity rate of $2.54
per kilowatt/month (kW/month) for a composite rate of 11.58 mills/kWh.
Step one of the provisional P-DP rates for transmission service
consists of a firm transmission service rate of $10.40 per kilowatt/
year (kW/year), a nonfirm transmission service rate of 1.98 mills/kWh,
and a firm transmission service rate for SLCA/IP of $5.20/kW/season. A
season for the firm transmission service rate for SLCA/IP is 6 months.
Step two of the provisional P-DP rates consists of an energy rate
of 6.01 mills/kWh and a capacity rate of $2.63/kW/month for a composite
rate of 12.01 mills/kWh. Step two of the provisional P-DP rates for
transmission service consists of a firm transmission service rate of
$12.55/kW/year, a nonfirm transmission service rate of 2.39 mills/kWh,
and a firm transmission service rate for SLCA/IP of $6.27/kW/season.
A comparison of existing P-DP rates and the two-step provisional P-
DP rates follows:
Comparison of Existing P-DP Rates and Step One Provisional P-DP Rates
------------------------------------------------------------------------
Provisional
Existing rates rates Percent
FY 1990 effective 2/1/ change (%)
1994*
------------------------------------------------------------------------
Power Rate Schedule........ PD-F3 PD-F4 ...........
Composite (mills/kWh)...... 9.03 11.58 28
Energy (mills/kWh)......... 4.52 5.79 28
Capacity ($/kW/month)...... 1.98 2.54 28
Firm Transmission Service
Rate Schedule............. PD-FT3 PD-FT4 ...........
Firm Transmission Service
($/kW/year)............... 8.20 10.40 27
Nonfirm Transmission
Service Rate Schedule..... PD-NFT3 PD-NFT4 ...........
Nonfirm Transmission
Service (mills/kWh)....... 1.50 1.98 32
Firm Transmission Service
for SLCA/IP Rate Schedule. PD-FCT3 PD-FCT4 ...........
Firm Transmission Service
for SLCA/IP ($/kW/season). 4.10 5.20 27
------------------------------------------------------------------------
*The first steps of the provisional P-DP rates are in effect from
February 1, 1994, through September 30, 1995.
Comparison of Existing P-DP Rates and Step Two Provisional P-DP Rates
------------------------------------------------------------------------
Provisional
Existing rates rates Percent
FY 1990 effective 10/1/ change (%)
1995*
------------------------------------------------------------------------
Power Rate Schedule........ PD-F3 PD-F4 ...........
Composite (mills/kWh)...... 9.03 12.01 33
Energy (mills/kWh)......... 4.52 6.01 33
Capacity ($/kW/month)...... 1.98 2.63 33
Firm Transmission Service
Rate Schedule............. PD-FT3 PD-FT4 ...........
Firm Transmission Service
($/kW/year)............... 8.20 12.55 53
Nonfirm Transmission
Service Rate Schedule..... PD-NFT3 PD-NFT4 ...........
Nonfirm Transmission
Service (mills/kWh)....... 1.50 2.39 59
Firm Transmission Service
For SLCA/IP Rate Schedule. PD-FCT3 PD-FCT4 ...........
Firm Transmission Service
for SLCA/IP ($/kW/season). 4.10 6.27 53
------------------------------------------------------------------------
*The second steps of the provisional P-DP rates are in effect from
October 1, 1995, through January 31, 1999, or until superseded.
DATES: The P-DP Rate Schedules PD-F4, PD-FT4, PD-NF4, and PD-FCT4 will
become effective on an interim basis beginning February 1, 1994, and
will be in effect until FERC confirms, approves, and places the rate
schedules into effect on a final basis for a 5-year period or until
superseded.
FOR FURTHER INFORMATION CONTACT:
Mr. Thomas A. Hine, Area Manager, Phoenix Area Office, Western Area
Power Administration, P.O. Box 6457, Phoenix, AZ 85005-6457, (602) 352-
2453
Ms. Deborah M. Linke, Director, Division of Marketing and Rates,
Western Area Power Administration, P.O. Box 3402, Golden, CO 80401-
3398, (303) 231-1545
Mr. Joel Bladow, Assistant Administrator for Washington Liaison,
Western Area Power Administration, Room 8G-061, Forrestal Building,
1000 Independence Avenue SW., Washington, DC 20585-0001, (202) 586-5581
SUPPLEMENTARY INFORMATION: By Amendment No. 3 to Delegation Order No.
0204-108, published November 10, 1993 (58 FR 59716), the Secretary of
Energy delegated (1) the authority to develop long-term power and
transmission rates on a nonexclusive basis to the Administrator of
Western; (2) the authority to confirm, approve, and place such rates
into effect on an interim basis to the Deputy Secretary; and (3) the
authority to confirm, approve, and place into effect on a final basis,
to remand, or to disapprove such rates to FERC. Existing DOE procedures
for public participation in power rate adjustments (10 CFR Part 903)
became effective on September 18, 1985 (50 FR 37837).
These power and transmission rates are established pursuant to the
DOE Organization Act (42 U.S.C. Sec. 7101 et seq.); the Reclamation Act
of 1902 (43 U.S.C. Sec. 371 et seq.) as amended and supplemented by
subsequent enactments, particularly section 9(c) of the Reclamation
Project Act of 1939 (43 U.S.C. Sec. 485h(c)); section 2 of the Rivers
and Harbors Act of 1935 (49 Stat. 1028, 1039); the Parker-Davis Act of
1954 (68 Stat. 143); Final Rule (10 CFR Part 904) published in the
Federal Register at 51 FR 43154 on November 28, 1986; the DOE financial
reporting policies, procedures, and methodology (DOE RA 6120.2 dated
September 20, 1979); and the procedures for public participation in
rate adjustments for power and transmission service marketed by Western
(10 CFR Part 903) published in the Federal Register at 50 FR 37837 on
September 18, 1985.
Based upon data available in fiscal year (FY) 1991, the PRS for the
P-DP showed that the existing composite rate of 9.03 mills/kWh for firm
power, firm transmission rate of $8.20/kW/year, nonfirm transmission
rate of 1.50 mills/kWh, and a firm transmission service rate for SLCA/
IP of $4.10/kW/season would not provide sufficient revenues to pay the
project costs within the prescribed time periods. The Ratesetting PRS
indicates substantial rate increases for firm power and firm and
nonfirm transmission service are required in order to meet revenue
requirements for FY 1994 through the end of the study. Because this
represents a substantial increase over the existing P-DP rates, Western
is proposing to implement a two-step rate process for firm power and
firm and nonfirm transmission service.
Rate increases are due largely to the increases in replacement and
addition activities on P-DP. The original P-DP investment was fully
paid in 1984 and the irrigation investment was fully paid in 1986.
However, the P-DP is undergoing a major replacement and
refurbishment plan needed for environmental compliance, safety, and
reliability. The rate increases can also be attributed to an increase
in purchased power expense. The increase in purchased power expense
resulted from flooding conditions along the Colorado River in
southwestern Arizona which created a generation deficiency.
During the 143-day comment period, Western received 31 written
comments. In addition, nine speakers commented during the September 11,
1992, public comment forum. During the second comment period of 70
days, Western received 19 written comments. In addition, seven speakers
commented during the July 14, 1993, public comment forum. All comments
and responses are addressed in the rate order.
Rate Order No. WAPA-55, confirming, approving, and placing the P-DP
proposed rate adjustments into effect on an interim basis is issued,
and the rate schedules PD-F4, PD-FT4, PD-NFT4, and PD-FCT4 will be
promptly submitted to FERC for confirmation and approval on a final
basis.
Issued in Washington, D.C., January 6, 1994.
William H. White,
Deputy Secretary.
Department of Energy
Deputy Secretary
In the matter of: Western Area Power Administration, Rate
Adjustments for Phoenix Area Office, Parker-Davis Project.
[Rate Order No. WAPA-55] order confirming, approving, and
placing the Parker-Davis Project; rates for firm power and firm and
nonfirm transmission service into effect on an interim basis.
January 6, 1994.
Pursuant to section 302(a) of the Department of Energy (DOE)
Organization Act, 42 U.S.C. Sec. 7152(a) et seq., the power marketing
functions of the Secretary of the Interior and the Bureau of
Reclamation (Reclamation) under the Reclamation Act of 1902, 43 U.S.C.
Sec. 371 et seq., as amended and supplemented by subsequent enactments,
particularly section 9(c) of the Reclamation Project Act of 1939, 43
U.S.C. Sec. 485h(c), and other acts specifically applicable to the
projects involved, were transferred to and vested in the Secretary of
Energy (Secretary).
By Amendment No. 3 to Delegation Order No. 0204-108, published on
November 10, 1993 (58 FR 59716), the Secretary delegated: (1) The
authority to develop long-term power and transmission rates on a
nonexclusive basis to the Administrator of the Western Area Power
Administration (Western); (2) the authority to confirm, approve, and
place such rates into effect on an interim basis to the Deputy
Secretary; and (3) the authority to confirm, approve, and place into
effect on a final basis, to remand, or to disapprove such rates to the
Federal Energy Regulatory Commission (FERC). Existing DOE procedures
for public participation in power rate adjustments (10 CFR Part 903)
became effective on September 18, 1985 (50 FR 37835).
Acronyms and Definitions
As used in this rate order, the following acronyms and definitions
apply:
AC Intertie: Pacific Northwest/Pacific Southwest Intertie
Project.
Additions: A unit of property constructed or acquired which
enhances or improves a project or system and which is properly
allocated to power or the joint features allocated to power.
Apportionment of Cost Study: A study that apportions costs to
users in proportion to benefits received from the respective P-DP
power and transmission system.
Composite Rate: Combination of an energy and a capacity
component.
Cost Evaluation Period (CEP): The first 5 future years in the
PRS. Normally consistent with the budget period.
CRSP: Colorado River Storage Project.
CSRS: Civil Service Retirement System.
Current PRS: The PRS included in this rate, which was used to
test adequacy of the P-DP existing rates.
Customer Brochure: A document prepared for public distribution
explaining the background of the rate proposal contained in this
rate order.
Deputy Secretary: The approval authority to confirm, approve,
and place rates into effect on an interim basis.
DOE: Department of Energy.
DOE Act: Department of Energy Organization Act, August 4, 1977
(42 U.S.C. 7101 et seq.).
DOE Order No. RA 6120.2: An order dealing with power marketing
administration financial reporting.
EIS: Environmental impact statement.
Energy Rate: Expressed in mills per kWh. Applied to each kWh
made available to each contractor.
Engineering Ten-Year Construction and Replacement Plan: A
planning document prepared by Western for transmission system
construction for a 10-year period. Also referred to as the
``Engineering Ten-Year Plan.''
FERC: Federal Energy Regulatory Commission.
FDR: Facilities development report. A planning document prepared
by Western for specific transmission system construction.
FY: Fiscal year.
IDC: Interest during construction.
Interior: U.S. Department of the Interior.
kW: Kilowatt.
kW/month: The greater of (1) the highest 30-minute demand
measured during the month, not to exceed the contract obligation, or
(2) the contract rate of delivery (kilowatt per month).
$/kW/month: Monthly charge for capacity (usage--$ per kilowatt
per month).
$/kW/season: 6-month charge for capacity (usage--$ per kilowatt
per season).
kWh: Kilowatthour.
MAF: Million acre-feet.
mills/kWh: Mills per kilowatthour.
Multiproject Costs: These are costs for facilities being charged
to one project that benefit other projects.
MW: Megawatt.
MWD: Metropolitan Water District of Southern California.
NEPA: National Environmental Policy Act of 1969 (42 U.S.C. 4321
et seq.).
O&M: Operation and maintenance.
P-DP: Parker-Davis Project.
PAO: Phoenix Area Office.
Pinch-point: The FY in which the level of the rate is set as
dictated by a revenue requirement in some future year to meet
relatively large annual costs or to repay investments which come
due.
PRS: Power repayment study.
Proposed Rate: A rate revision that the Administrator of Western
recommends to the Deputy Secretary for approval.
Provisional Rate: A rate which has been confirmed, approved, and
placed into effect on an interim basis by the Deputy Secretary.
Ratesetting PRS: The PRS that utilizes, in whole or part,
proposed or assigned rates. It is designed to demonstrate that
potential revenue levels will satisfy the cost recovery criteria
over the remainder of the power system's repayment period.
Reclamation: Bureau of Reclamation, U.S. Department of the
Interior.
Replacements: A unit of property constructed or acquired as a
substitute for an existing unit of property for the purpose of
maintaining the power features of a project or the joint features
properly allocated to power.
Replacement Study: The cyclical analysis of replacement service
lives. A high level of replacement activity for a few consecutive
years will reoccur in future years at a similar high level with the
years in between tending to be at a lesser level of replacement.
Secretary: Secretary of Energy.
SLCA: Salt Lake City Area.
SLCA/IP: The Salt Lake City Area Integrated Projects, which
encompass the combined sales and resources of the CRSP, Collbran,
and Rio Grande Projects.
Treasury: Secretary of the Department of the Treasury.
Upper Basin: That part of the Colorado River Basin consisting of
the southwestern part of Wyoming, western Colorado, most of New
Mexico, Utah, and the northwestern section of Arizona.
Western: Western Area Power Administration, DOE.
Effective Date
Western is proposing to implement a two-step rate process for firm
power and firm and nonfirm transmission service. Step one of the P-DP
provisional rates for firm power and firm and nonfirm transmission
service will become effective on an interim basis beginning February 1,
1994. Step two of the provisional P-DP rates will become effective
October 1, 1995, through January 31, 1999. The P-DP provisional rates
will be in effect until FERC confirms, approves, and places the rate
schedules into effect on a final basis for a 5-year period, or until
superseded.
Public Notice and Comment
The procedures for public participation in power and transmission
rate adjustments and extensions, 10 CFR Part 903, have been followed by
Western in the development of the P-DP firm power and firm and nonfirm
transmission rates. The provisional P-DP rates for firm power and firm
and nonfirm transmission service represent an increase of more than 1
percent in total P-DP revenues; therefore, it is a major rate
adjustment as defined at 10 CFR Secs. 903.2(e) and 903.2(f)(1). The
distinction between a minor and major rate adjustment is used only to
determine the public procedures for the rate adjustment.
The following summarizes the steps Western took to ensure
involvement of interested parties in the rate process:
1. A Federal Register notice was published on May 8, 1992 (57 FR
19904), officially announcing the proposed P-DP rate adjustments for
firm power and firm and nonfirm transmission service; initiating the
public consultation and comment period; announcing the June 19, 1992,
public information forum and the June 30, 1992, public information and
comment forum; and presenting procedures for public participation.
2. A letter was mailed to all P-DP customers and other interested
parties on May 19, 1992, providing a copy of the P-DP proposed rate
adjustments brochure and announcing the informal customer meeting. The
informal customer meeting was held on June 3, 1992, in Phoenix,
Arizona. At this informal meeting, Western representatives explained
the need for the increase and answered questions from those attending.
3. At the public information forum held on June 19, 1992, Western
explained the need for the proposed rate adjustments and answered
questions from those attending. Western also announced a second public
comment forum and the extension of the consultation and comment period
for the P-DP.
4. At the public information forum and public comment forum held on
June 30, 1992, Western explained the need for the proposed P-DP rate
adjustments in greater detail and answered questions.
5. On August 6, 1992, a Federal Register notice was published (57
FR 34776) formally announcing the extension of the consultation and
comment period through September 28, 1992, for the proposed rate
adjustments for the P-DP.
6. An additional public comment forum was held on September 11,
1992, to give the public an opportunity to comment on the proposed P-DP
rates for the record. Nine people, who represent customers and customer
groups, made oral comments.
7. Thirty-one written comment letters were received during the 143-
day consultation and comment period. The consultation and comment
period ended September 28, 1992.
8. A letter was mailed to all P-DP customers and other interested
parties on June 29, 1993, announcing the reopening of the consultation
and comment period and providing a copy of an addendum to the P-DP
proposed rate adjustments brochure. This letter also announced the
public information/public comment forum to be held on July 14, 1993, in
Phoenix, Arizona.
9. On July 13, 1993, a Federal Register notice was published (58 FR
37731) formally announcing the reopening of the consultation and
comment period on the proposed P-DP firm power and firm and nonfirm
transmission service rate adjustments.
10. At the public information forum held on July 14, 1993, Western
representatives explained the need to reopen the consultation and
comment period and answered questions. The consultation and comment
period was reopened due to an unexpected increase in purchased power in
FY 1993.
11. The public comment forum was held on July 14, 1993, to give the
public another opportunity to comment on the proposed P-DP rates for
the record. Seven people, who represent customers and customer groups,
made oral comments.
12. Nineteen written comment letters were received during the
second consultation and comment period of 70 days. The second
consultation and comment period ended on September 7, 1993.
Project History
The Parker Dam Power Project was authorized by section 2 of the
Rivers and Harbors Act of August 30, 1935 (49 Stat. 1028, 1039), and
the Davis Dam Project was authorized April 26, 1941, by the Acting
Secretary of the Interior under Provisions of the Reclamation Project
Act of 1939 (43 U.S.C. Sec. 485 et seq.). The P-DP was formed by the
consolidation of the two projects under the terms of the Act of May 28,
1954 (68 Stat. 143).
Davis Dam, which creates Lake Mohave, provides regulation, both
hourly and seasonally, of the water releases from Lake Mead (through
Hoover Dam and Powerplant) to facilitate water delivery for downstream
irrigation requirements and for water delivery beyond the boundary of
the United States as required by the Mexican Water Treaty. Operation of
the powerplant began in January 1951 with a generating capacity of
225,000 kW. During the period 1974-78 the generator nameplate capacity
was increased to 240,000 kW by rewinding the generator stators.
Construction of Parker Dam was authorized for the purposes of
controlling floods, improving river navigation, regulating the flow of
the Colorado River, providing for storage and for the delivery of the
stored waters thereof, for the reclamation of public lands and Indian
reservations and for other beneficial uses, and for the generation of
electric energy as a means of making the P-DP a self-supporting and
financially solvent undertaking.
Parker Dam was constructed by Reclamation with funds advanced by
MWD. Lake Havasu, the reservoir created behind Parker Dam, serves as
the forebay from which water is diverted into the MWD aqueduct. The
aqueduct delivers a major portion of California's entitlement of
Colorado River water to southern California and is the diversion point
for delivering Central Arizona Project water to Arizona. The reservoir
operation is limited to minor storage fluctuations. The dam provides a
head of approximately 75 feet for the Parker Powerplant. Reclamation
began operation of the Parker Powerplant in December 1942. Although the
total generator nameplate capacity is 120,000 kW, the powerplant
capacity is essentially limited to 104,000 kW because of operating
constraints of downstream physical structures, primarily Headgate Rock
Dam. Under contract, MWD is entitled to one-half of the net energy
generated by the Parker Powerplant at any given time.
All facilities of the P-DP were operated and maintained by
Reclamation until the formation of DOE pursuant to the DOE Act, enacted
by Congress on August 4, 1977. Pursuant to section 302 of the DOE Act
(42 U.S.C. Sec. 7152), responsibility for the power marketing functions
of Reclamation, including the construction, operation, and maintenance
of substations, transmission lines, and attendant facilities, was
transferred to Western. The responsibility for operation and
maintenance of the dams and powerplants remains with Reclamation.
Power Repayment Studies
PRSs are prepared each FY to determine if power revenues will be
sufficient to pay, within the prescribed time periods, all costs
assigned to the power function. Repayment criteria are based on law,
policies, and authorizing legislation. DOE Order No. RA 6120.2, section
12.b, states:
In addition to the recovery of the above costs (operation and
maintenance and interest expenses) on a year-by-year basis, the
expected revenues are at least sufficient to recover (1) each dollar
of power investment at Federal hydroelectric generating plants
within 50 years after they become revenue producing, except as
otherwise provided by law; plus, (2) each annual increment of
Federal transmission investment within the average service life of
such transmission facilities or within a maximum of 50 years,
whichever is less; plus, (3) the cost of each replacement of a unit
of property of a Federal power system within its expected service
life up to a maximum of 50 years; plus, (4) each dollar of assisted
irrigation investment within the period established for the
irrigation water users to repay their share of construction costs;
plus (5) other costs such as payments to basin funds, participating
projects, or States.
Existing and Provisional P-DP Rates
A comparison of existing P-DP rates and two-step provisional P-DP
rates follows:
Comparison of Existing P-DP Rates and Step One Provisional P-DP Rates
------------------------------------------------------------------------
Provisional
Type of Service Existing rates rates 2/1/ Percent
10/1/1990 1994* change (%)
------------------------------------------------------------------------
Power Rate Schedule........ PD-F3 PD-F4 ...........
Composite (mills/kWh)...... 9.03 11.58 28
Energy (mills/kWh)......... 4.52 5.79 28
Capacity ($/kW/month)...... 1.98 2.54 28
Firm Transmission Rate
Service Schedule.......... PD-FT3 PD-FT4 ...........
Firm Transmission Service
($/kW/year)............... 8.20 10.40 27
Nonfirm Transmission
Service Rate Schedule..... PD-NFT3 PD-NFT4 ...........
Nonfirm Transmission
Service (mills/kWh)....... 1.50 1.98 32
Firm Transmission Service
For SLCA/IP Rate Schedule. PD-FCT3 PD-FCT4 ...........
Firm Transmission Service
for SLCA/IP ($/kW/season). 4.10 5.20 27
------------------------------------------------------------------------
*The first steps of the provisional P-DP rates are in effect from
February 1, 1994, through September 30, 1995.
Comparison of Existing P-DP Rates and Step Two Provisional P-DP Rates
------------------------------------------------------------------------
Provisional
Type of service Existing rates rates 10/1/ Percent
10/1/1990 1995* change (%)
------------------------------------------------------------------------
Power Rate Schedule........ PD-F3 PD-F4 ...........
Composite (mills/kWh)...... 9.03 12.01 33
Energy (mills/kWh)......... 4.52 6.01 33
Capacity ($/kW/month)...... 1.98 2.63 33
Firm Transmission Service
Rate Schedule............. PD-FT3 PD-FT4 ...........
Firm Transmission Service
($/kW/year)............... 8.20 12.55 53
Nonfirm Transmission
Service Rate Schedule..... PD-NFT3 PD-NFT4 ...........
Nonfirm Transmission
Service (mills/kWh)....... 1.50 2.39 59
Firm Transmission Service
For SLCA/IP Rate Schedule. PD-FCT3 PD-FCT4 ...........
Firm Transmission Service
for SLCA/IP ($/kW/season). 4.10 6.27 53
------------------------------------------------------------------------
*The second steps of the provisional P-DP rates are in effect from
October 1, 1995, through January 31, 1999, or until superseded.
Certification of Rates
Western's Administrator has certified that the P-DP firm power and
firm and nonfirm transmission service rates placed into effect on an
interim basis herein are the lowest possible consistent with sound
business principles. The rates have been developed in accordance with
administrative policies and applicable laws.
Discussion
Based upon FY 1991 data, the PRS for the P-DP showed that the
existing composite rate of 9.03 mills/kWh for firm power, a
transmission rate of $8.20/kW/year, a nonfirm transmission service rate
of 1.50 mills/kWh, and a firm transmission service rate for SLCA/IP of
$4.10/kW/season would not provide sufficient revenues to pay the
project costs within the prescribed time periods. The Ratesetting PRS
indicates that a substantial rate adjustment for firm power and firm
and nonfirm transmission service is required to meet revenue
requirements for FY 1994 through the end of the study. Because the firm
transmission service rate adjustments are substantial increases over
the existing P-DP rates, and in response to customer requests and
comments, Western is proposing to implement a two-step rate process for
firm power and firm and nonfirm transmission service.
The provisional P-DP rates filed with FERC have been updated from
the rates originally proposed in the customer brochure and Federal
Register notice dated May 8, 1992. The changes to the Ratesetting PRS
are summarized as follows:
--Multiproject costs were updated through September 30, 1991. The PAO
is heavily involved in the process of total quality improvement and has
a Process Improvement Team (PIT) evaluating the multiproject cost
process. This PIT is made up of representatives from Engineering,
Operations, Budget, Finance, and Rates. Recommendations concerning an
improved process are expected to be published and implemented (if
approved) early in 1994. To the extent implemented recommendations make
a change in multiproject cost allocations and in rates, changes will be
reflected in subsequent rate processing.
--Replacement and addition projections in the cost evaluation period
were changed to incorporate ``The Engineering Ten-Year Construction and
Replacement Plan'' dated July 1992 for the cost evaluation period.
--Extraordinary costs were excluded from out years (FY 1998-2047)
resulting in minor reductions in estimates of O&M costs.
--Future-year replacements in FY 1998-2047 are projected at the most
current interest rate of 7.875 percent as compared to the FY 1991
interest rate of 8.50 percent.
--Projections used in FY 1992 for O&M, interest expense, and operating
revenues were updated to FY 1992 actuals as stated in Western's and
Reclamation's FY 1992 financial statements.
--The proposed P-DP rates for firm power and firm and nonfirm
transmission service were initially proposed as a single-step rate
increase effective for a 5-year period beginning October 1, 1993.
However, in response to customer comments, Western is proposing to
implement a two-step rate process. Step one of the provisional P-DP
rates will become effective February 1, 1994. Step two of the
provisional P-DP rates will become effective October 1, 1995.
--The FY 1993 purchased power expense has been updated.
The existing and provisional annual revenue requirements for the P-
DP* are as follows:
---------------------------------------------------------------------------
*The first steps of the provisional P-DP rates are in effect
from February 1, 1994, through September 30, 1995. The second steps
of the P-DP provisional rates are in effect from October 1, 1995,
through January 31, 1999, or until superseded.
Annual Revenue Requirements
------------------------------------------------------------------------
Provisional step one Provisional step two
Existing rates (FY 1994-95) rates (FY 1996-98)
------------------------------------------------------------------------
$28,348,137............ $36,083,885 $42,068,860
------------------------------------------------------------------------
The rate increase is necessary to satisfy the cost-recovery
criteria set forth in DOE Order No. RA 6120.2.
Apportionment of Cost Study
The provisional P-DP rates for firm and nonfirm transmission
service were based on the Apportionment of Cost Study that analyzed the
split between annual transmission service and power service costs. The
firm transmission service rate is established to assure that the P-DP
customers have an equitable share in payment of costs associated with
the P-DP transmission system. The beneficiaries of the P-DP
transmission system include customers for firm electric service, firm
transmission service, and firm transmission service for SLCA/IP power.
The Apportionment of Cost Study, dated FY 1977, determined an
apportionment of 55 percent and 45 percent for power costs and
transmission costs respectively. The latest Apportionment of Cost
Study, dated FY 1992, determined separate apportionments for step one
of the provisional P-DP rates and step two of the provisional P-DP
rates. The apportionments for step one of the provisional P-DP rates
are 34.11 percent for power costs and 65.89 percent for transmission
service costs. The apportionments for step two of the provisional P-DP
rates are 25.82 percent for power costs and 74.18 percent for
transmission service costs.
Since the 1977 Apportionment of Cost Study was completed, P-DP's
initial power investment has been repaid and the transmission system
has deteriorated, requiring more replacement and refurbishment
activities. These factors are causing a shift from power to
transmission service related costs in the Apportionment of Cost Study.
The provisional P-DP rates for firm transmission service will earn an
additional annual amount of $5,670,495 from 1994-95 and $9,857,542 from
1996-2047.
The current Apportionment of Cost Study derives the percentage of
required revenues to be recovered from firm power customers and firm
transmission customers. The study is performed separately for each step
of the P-DP provisional rates. Western has adopted a three-step process
that evaluates capital expenditures, annual operating expenses and
other revenue, and customer use of the P-DP transmission system. The
first step of the study assigns project investments to either the power
system or the transmission system. This step is used in the second step
of the Apportionment of Cost Study.
The second step entails apportioning annual operating costs and
other revenues to either the power system or the transmission system.
Annual operating costs and other revenues were determined by taking an
annual average of future years in the cost evaluation period. Annual
costs include O&M, multiproject, CSRS, interest, and principal
payments. Other revenues include rent and miscellaneous, fuel
replacement, multiproject, project use, and nonfirm transmission
service. If an annual operating cost or a component of other revenue
was determined to benefit both the power and transmission system, the
apportionment was assigned in accordance with the apportionment of
investment costs derived in the first step.
The transmission system is used to deliver power committed under
electric service contracts. Therefore, a portion of the transmission
system cost should be recovered by power sales revenues. The third step
of the Apportionment of Cost Study determines the share of transmission
costs to be recovered by power sale revenues. Annual costs are assigned
to transmission or power production on the basis of power system use by
each customer. The assignment by use is based upon contract capacity
commitments for the P-DP transmission system. Users of the P-DP
transmission system include customers for (1) P-DP wholesale firm
energy, (2) P-DP firm transmission service, (3) SLCA/IP firm
transmission service, and (4) project use. Commitments under
transmission service agreements are assigned to transmission, while
commitments under electric service contracts and project use are
assigned to power production. The tables below show the development of
revenue requirements from power sales and transmission service
agreements and the assignment of cost into their related revenue
categories.
Step One P-DP Provisional Rates Apportionment of Cost
------------------------------------------------------------------------
Total Power Transmission
------------------------------------------------------------------------
Required Revenue....... $26,087,096 $5,691,780 $20,395,316
Contract Capacity
Commitments........... 1,790,191 kW 281,515 kW 1,508,676 kW
Percent of Total
Capacity.............. 100% 15.73% 84.27%
Assign 15.73 Percent
Transmission to Power. .............. $3,207,249 ($3,207,249)
Total Required Revenue. $26,087,096 $8,899,029 $17,188,067
Percentage to Be
Applied in Rate Design 100% 34.11% 65.89%
------------------------------------------------------------------------
Step Two P-DP Provisional Rates Apportionment of Cost
------------------------------------------------------------------------
Total Power Transmission
------------------------------------------------------------------------
Required Revenue....... $31,061,469 $3,925,744 $27,135,725
Contract Capacity
Commitments........... 1,865,665 kW 281,515 kW 1,584,150 kW
Percent of Total
Capacity.............. 100% 15.09% 84.91%
Assign 15.09 Percent
Transmission to Power. .............. $4,094,580 ($4,094,580)
Total Required Revenue. $31,061,469 $8,020,324 $23,041,145
Percentage to Be
Applied in Rate Design 100% 25.82% 74.18%
------------------------------------------------------------------------
The P-DP provisional rates for firm power and firm and nonfirm
transmission service are based on the apportionment percentages applied
to additional annual revenue requirements as derived in the Ratesetting
PRS.
Alternative Transmission Rates
As stated in the Federal Register notice published on May 8, 1992
(57 FR 19904), Western proposed alternative P-DP rates for both firm
and nonfirm transmission service. The proposed alternative rates would
have set a single rate for the use of either or both the P-DP and the
AC Intertie transmission systems. However, based on customers'
requests, Western decided not to propose the alternative transmission
service rates at this time.
Replacement and Addition Activities
The provisional P-DP rate adjustments are due largely to an
increase in replacements and additions on P-DP. P-DP is undergoing a
major replacement and refurbishment plan needed for environmental
compliance, safety, and reliability. Western initially used data from
the FY 1993 construction budget for replacement and addition activities
during the CEP (1994-98). However, during the consultation and comment
period, Western decided to reevaluate the replacement and addition
activities because of the economic strain being placed on the P-DP
customers and because of the unrealistic expectations that all
replacement and addition activities would be completed during the CEP.
Western compared the data from the FY 1993 construction budget
documents with the most current construction data as stated in ``The
Engineering Ten-Year Construction and Replacement Plan'' dated July
1992. The Engineering Ten-Year Plan showed the most current
construction data Western had on replacement and addition activities
over the next 10 years. Western made the decision to revise the
Ratesetting PRS by incorporating the most current data from the
Engineering Ten-Year Plan. All of the replacements and additions in the
Ratesetting PRS are authorized power system facilities for which
Congress has appropriated funds for FY 1993 construction, and which
will be in service within the CEP. Thus, the Ratesetting PRS only
incorporates the first 5 years of the Engineering Ten-Year Plan. These
revisions, based on data from the Engineering Ten-Year Plan, will help
maintain the lowest rate possible without jeopardizing the crucial need
of a safe and reliable P-DP transmission system. A comparison of the
initial ratesetting PRS using the FY 1993 construction budget to the
Ratesetting PRS using the Engineering Ten-Year Plan follows:
FY 1993 Construction Budget vs. Engineering Ten-Year Plan ($1,000)
------------------------------------------------------------------------
FY 1993
Addition and replacement construction Engineering ten- Difference
activities budget year plan
------------------------------------------------------------------------
Five-Year Plan/Year in $8,846/1992 $10,065/19941.. $1,219
Service.
Five-Year Plan (Phase 2)/ 11,268/1994 12,327/1995.... 1,059
Year in Service.
ED-5 Substation/Year in 3,238/1997 Will be (3,238)
Service. completed
beyond the CEP.
Phoenix Substation/Year 9,466/1992 9,525/19941.... 59
in Service.
Replace Mesa Substation/ 2,774/1992 Combined with (2,774)
Year in Service. Rogers
Substation.
Rogers Substation/Year in 1,525/1993 6,745/1994 (see 5,220
Service. #5.
Replace SCADA System/Year 10,970/1993 12,765/1994.... 1,795
in Service.
Davis Switchyard/Year in 3,238/1993 3,607/1994..... 369
Service.
Maricopa Substation/Year 156/1993 Will be (156)
in Service. completed
beyond the CEP.
Coolidge Substation/Year 6,677/1994 7,456/1994..... 779
in Service.
ED-2 Substation/Year in 5,670/1994 7,963/1995..... 2,293
Service.
Gila/Gila Valley 1,177/1995 Will be (1,177)
Transmission Line/Year completed
in Service. beyond the CEP.
Signal Substation/Year in 1,535/1995 Will be (1,535)
Service. completed
beyond the CEP.
Maintenance Facilities at 2,728/1995 Will be (2,728)
Gila/Year in Service. completed
beyond the CEP.
Maintenance Facilities at 3,123/1995 2,209/1995..... (914)
Coolidge Substation/Year
in Service.
Basic Substation/Year in 16,347/1995 17,236/1995.... 889
Service.
Hoover-Mead Basic Line 6,997/1995 4,189/1996..... (2,808)
Upgrade/Year in Service.
Gila Substation/Year in 9,390/1996 Will be (9,390)
Service. completed
beyond the CEP.
Maricopa-Saguaro 115-kV 15,238/1997 Will be (15,238)
Transmission Line/Year completed
in Service. beyond the CEP.
Mead Substation Stage 5/ 1,440/1994 1,430/1994..... (10)
Year in Service.
ED-4 Substation/Year in 5,685/1994 8,919/1995..... 3,234
Service.
----------------------------------------------
Total Difference......... ............... ............... (23,052)
------------------------------------------------------------------------
\1\As of October 1, 1993, the 5-Year Plan and the Phoenix Substation
have not been completed. Western is assuming these construction-work-
in-process activities will be completed plant in service in FY 1994.
There are other replacement and addition activities in Western's
O&M budget documents which are not included in the Engineering Ten-Year
Plan. These items are mostly communication equipment, including
microwave equipment and remote terminal units. Each of these O&M budget
activities was compared to the most recent data and revised to reflect
an overall reduction of $1.5 million in FY 1997. Western will continue
to evaluate the implementation of the Engineering Ten-Year Plan and
adequacy of the provisional P-DP rates and will include any changes in
future rate adjustments.
The capitalized costs for future replacements and additions in the
cost evaluation period include IDC. The IDC calculation for each
replacement is determined by the interest rate in the year construction
begins. The annual interest expense for replacements and additions is
also based on the interest rate in the year construction begins. The
cumulative investment cost for replacements through the cost evaluation
period is $115,859,859. The cumulative investment cost for additions
through the cost evaluation period is $126,839,043.
The replacement program is used to forecast replacements in years
1999-2047. The replacement program showed low replacement levels in
some FYs and high levels in other years. Western believes that only a
certain amount of work can be done in any given year. Therefore,
Western decided to average the replacement numbers to reflect a stable
level of replacements which could be supported over the long term.
Purchased Power Expense
The consultation and comment period was reopened due to the
increase in purchased power expense for FY 1993. Data for purchased
power were initially based on the FY 1993 congressionally approved
budget. However, during FY 1993, current actual expenses for purchased
power far exceed the original FY 1993 congressional budget estimate of
$700,000. The current expenses for purchased power for FY 1993 are
$5,000,000. This change in purchased power expense has led to an
increase in the firm power rate. The increase in purchased power
expense resulted from flooding conditions along the Colorado River in
southwestern Arizona, which created a generation deficiency.
Statement of Revenue and Related Expenses
The following table provides a summary of revenue and expense data
for the 5-year provisional rate approval period.
Parker-Davis Project: Comparison of 5-Year Rate Period (1994-98);
Revenues and Expenses
[In thousands of dollars]
------------------------------------------------------------------------
FY 1987 Ratesetting
PRS, FY PRS, FY Difference
1994-98 1994-98
------------------------------------------------------------------------
Revenues:
Project Use..................... 6,025 6,025 0
Firm Commercial................. 51,946 68,100 16,154
Transmission and Other Revenue.. 39,642 124,249 84,607
Cumulative Surplus.............. \1\11,309 0 (11,309)
Capitalized Expenses............ 0 0 0
-------------------------------------
Total Revenues................ 108,922 198,374 89,452
Revenue Distribution:
Operations and Maintenance...... 78,961 125,938 46,997
Purchased Power................. 0 2,800 2,800
Interest Expense................ 2,006 55,738 53,732
Other Deductions................ 0 2,619 2,619
Investment Repayment\2\......... 27,955 11,279 (16,676)
Cumulative Surplus.............. 0 0 (0)
-------------------------------------
Total......................... 108,922 198,374 89,452
Principal Payments:
Payments on Deficit............. 0 5,392 5,392
Payments on Project............. 0 0 0
Payments on Additions........... 0 5,887 5,887
Payments on Replacements........ 27,955 0 (27,955)
Payments on Irrigation Aid...... 0 0 0
-------------------------------------
Total......................... 27,955 11,279 (16,676)
Cumulative Investment (as of FY
1998):
Project......................... 108,338 108,338 0
Additions....................... 31,561 126,839 95,278
Replacements.................... 71,640 115,860 44,220
Irrigation Aid.................. 26,770 26,770 0
-------------------------------------
Total......................... 238,309 377,807 139,498
Unpaid Federal Investment (as of
FY 1998):
Project......................... 0 0 0
Additions....................... 0 65,169 65,169
Replacements.................... 25,170 89,908 64,738
Irrigation Aid.................. 0 0 0
Total......................... 25,170 155,077 129,907
------------------------------------------------------------------------
\1\Cumulative surplus applied FY 1994.
\2\Includes principal payments for capitalized deficits, replacements,
and additions.
Basis for Rate Development--P-DP
Firm Power Rate
The provisional firm power P-DP rate was designed to reflect the
power/transmission split as derived in the Apportionment of Cost Study
and continues to maintain a 50/50 split between revenue from energy and
capacity rates based on a 60-percent load factor.
Step one of the provisional P-DP rates consists of a 5.79 mills/kWh
energy rate and $2.54/kW/month capacity rate effective February 1,
1994. The necessary composite rate is 11.58 mills/kWh, which is an
increase of 28 percent over the existing composite rate of 9.03 mills/
kWh.
Step two of the provisional P-DP rates consists of a 6.01 mills/kWh
energy rate and $2.63/kW/month capacity rate effective October 1, 1995.
The necessary composite rate is 12.01 mills/kWh, which is an increase
of 33 percent over the existing composite rate of 9.03 mills/kWh.
Transmission Service Rates
The provisional firm transmission service P-DP rate was designed to
reflect the power/transmission split as derived in the Apportionment of
Cost Study. Step one of the provisional P-DP rates for firm
transmission service is $10.40/kW/year ($.87/kW/month) and nonfirm
transmission service is 1.98 mills/kWh. The step-one rate for firm
transmission service for SLCA/IP is $5.20/kW/season ($.87/kW/month). A
season for the firm transmission service rate for SLCA/IP is 6 months.
Step two of the provisional P-DP rates for firm transmission
service is $12.55/kW/year ($1.05/kW/month) and nonfirm transmission
service is 2.39 mills/kWh. The step two rate for firm transmission
service for SLCA/IP is $6.27/kW/season ($1.05/kW/month).
Comments
During the 143-day comment period, Western received 31 written
comments. In addition, nine speakers commented during the September 11,
1992, public comment forum. During the reopening of the comment forum
of an additional 70 days, Western received 19 written comments. In
addition, seven speakers commented during the July 14, 1993, public
comment forum. All comments were reviewed and considered in the
preparation of this rate order.
Written comments were received from the following sources:
Aguila Irrigation District (Arizona)
Ak-Chin Indian Community (Arizona)
Arizona Municipal Power Users' Association (Arizona)
Arizona Power Pooling Association (Arizona)
Arizona Public Service Company (Arizona)
Buckeye Water Conservation & Drainage District (Arizona)
Basic Management, Inc. (Nevada)
Central Arizona Water Conservation District (Arizona)
Chemstar Lime Company (Arizona)
Colorado River Commission of Nevada (Nevada)
Electrical District Number Two, Pinal County (Arizona)
Electrical District Number Five, Pinal County (Arizona)
Electrical District Number Seven (Arizona)
Harquahala Irrigation District (Arizona)
Irrigation and Electrical Districts Association of Arizona (Arizona)
Maricopa Water District (Arizona)
McMullen Valley Water Conservation and Drainage District (Arizona)
Metropolitan Water District of Southern California (California)
Meyer, Hendricks, Victor, Osborn & Maledon (Arizona)
Nevada Power Company (Nevada) 25 Overton Power District No. 5
(Nevada)
Pioneer Chlor-Alkali (Nevada)
Roosevelt Irrigation District (Arizona)
Roosevelt Water Conservation District (Arizona)
Safford, City of, Arizona, (Arizona)
Salt River Project (Arizona)
San Carlos Irrigation and Drainage District (Arizona)
Southern California Edison (California)
Titanium Metal Corporations (Nevada)
Tonopah Irrigation District (Arizona)
Valley Electric Association, Inc. (Nevada)
Representatives of the following organizations made oral comments:
Arizona Power Authority--Leroy Michael, Jr. & David Helsby (Arizona)
Basic Management, Inc.--Richard F. Brown. (Nevada)
Colorado River Commission of Nevada--Thomas Cahill, Don Allen, and
David Luttrell (Nevada)
Five Hoover Customer Entities--Jay I. Moyes (Arizona)
Irrigation & Electrical Districts Association of Arizona--Robert S.
Lynch (Arizona)
Overton Power District No. 5 and Valley Electric Association--Jim
McManus (Nevada)
Pioneer Chlor-Alkali Company--Terry Graves (Nevada)
Salt River Project--Leslie James & Jim Transgrud (Arizona)
Most of the comments received at the public meetings and in
correspondence dealt with costs of annual expenses, replacements and
additions, the proposed alternative transmission service rates,
consideration of stepped rates, and the Apportionment of Cost Study.
All comments were considered in developing the provisional P-DP rates.
The comments and responses, paraphrased for brevity, are discussed
below. Direct quotes from comment letters are used for clarification
where necessary.
Parker-Davis Comments
Operation and Maintenance Costs
Comment: Western's ``General Western Allocation'' expenses are too
high and they are unfairly charged to P-DP. Western should explain the
justification of the allocating of costs from its Washington, D.C., and
Golden, Colorado, offices.
Response: Western's indirect costs are divided into three
categories: Associated direct expense (ADE), administrative and general
expense (AGE), and general Western allocation (GWA). ADE consists of
undistributed costs and expenses for all types of direct costs which
possess a clear relationship to benefiting activities and are recovered
in the power rate base. AGE costs are general and administrative
expenses benefiting ratepayers and represent primarily costs for
nonmanagerial staff and support. GWA is a subset of AGE and includes
ADP expenses, general office supplies, contracted administrative
services, etc. Independent auditors have determined that AGE and GWA
exclusively benefit ratepayers and should be recovered as part of the
costs included in the power rate base. The indirect cost distribution
system was designed and endorsed by a major accounting firm and is
consistent with industry standards. Western does not believe these
costs are excessive in the manner in which they are distributed.
Comment: In light of the extensive replacement and addition program
being carried out by Western, O&M costs are not projected to decline in
the future as supposedly older, high maintenance equipment is replaced
with newer, lower maintenance equipment.
Comment: Western feels it is necessary to overestimate operation
and maintenance expenses as some sort of safeguard in the budget and
planning process. This is most recently seen by comparison of budget to
actual numbers for FY 92. We believe a sharper pencil should be taken
to those O&M projections in the process.
Response: O&M costs are projected in the future in accordance with
DOE Order No. RA 6120.2. It is Western's policy, as in section 10,
paragraph 2(f) of DOE Order No. RA 6120.2, to estimate O&M costs based
on historical cost trends and actual project costs from the past.
During the cost evaluation period, O&M expense is based on the FY 1993
budget, and projections for FY 1999 through FY 2047 are held constant
based on the last year in the cost evaluation period less extraordinary
maintenance. O&M does decline in the cost evaluation period. Western
has a cost containment committee which reviews and evaluates the O&M
budget. The committee's goals are to achieve the lowest O&M budget
possible for Western. Therefore, Western does not believe that
projections for the operation and maintenance budgets are overstated.
Comment: Rate impact analysis was not performed prior to seeking
congressional authorization for budgeted O&M expenditures.
Comment: Western and Reclamation have not attempted to limit O&M
expense.
Response: Although specific rate impact analyses were not
performed, Western and Reclamation have placed a priority on cost
containment. The formation of Western's Cost Containment Committee
takes into consideration all impacts to the rates. Cost containment
plays a major role in the preparation of Western's and Reclamation's
O&M budgets. Western has invited the customers into the planning
process, which will evaluate programs and rate impacts.
Comment: Power Accounting and Collection, Conservation and
Renewable Energy, and Power Marketing and General Resource Planning has
increased 39.6 percent from FY 1991 and FY 1992. Total O&M increased
38.0 percent from FY 1991 to FY 1992. The magnitude of projected
expenditures for O&M on an average annual basis exceeded the rate of
inflation by 4.1 percent per year.
Comment: P-DP O&M expenses have run counter to the regional and
local trends and forecasts for electric utilities. The cost projections
for replacements and additions for the 5-year rate evaluation programs
and the study period appear to be singular in the industry from the
standpoint of magnitude. Since the late 1980's, the trend in the
Pacific and Rocky Mountain Southwest has been to keep O&M expenses and
replacement cost increases below the rate of inflation.
Response: Western has revised the PRS to reflect actual
expenditures in FY 1992. Power Accounting and Collection, Conservation
and Renewable Energy, and Power Marketing and General Resource Planning
have increased 5.00 percent from FY 1991 to FY 1992. One contributing
factor to the increased O&M is that the consolidation of the Boulder
City Area Office and the Phoenix District Office was made during FY
1991, having an effect on staffing levels and work being performed.
Specific division (e.g., power marketing) activities were put off until
the division could acquire staff. The average increase of O&M cost per
year over the cost evaluation period is 1.46 percent, which is below
the rate of inflation.
Comment: Western has failed to explain why administrative and
general costs increased dramatically following the move of its regional
office to Phoenix and the consolidation of its other offices,
particularly since WAPA claimed that these changes would reduce costs
by $1.5 million annually.
Response: Western's administrative and general costs have not
dramatically increased since moving the regional office to Phoenix and
consolidating other offices. According to Western's FY 1992 financial
statement, the general Western allocation portion for the Phoenix Area
has actually decreased from $2.6 million in FY 1991 to $2.2 million in
FY 1992, which represents a decrease of 15 percent. The Phoenix Area's
AGE also decreased from $1.5 million in FY 1991 to $1.3 million in FY
1992, which represents a decrease of 13 percent. Western had estimated
an overall savings of $1.5 million annually. However, the consolidation
was not completed until FY 1992. Western believes the full recognition
of savings from the consolidation has not yet become evident.
Alternative Transmission Rates
Comment: Customers renew their support for the alternative
transmission rates.
Comment: Customers do not support the alternative transmission
rates because of subsidizing and project repayment issues. Each
transmission project should be planned, designed, and operated on its
own merit.
Response: Since Western and the customers agreed not to recommend
implementation of the alternative transmission service rates, Western
plans to implement separate P-DP and AC Intertie rates for firm
transmission service and nonfirm transmission service.
Comment: Western should conduct further studies to determine the
feasibility of complete operational integration of the various
transmission facilities in the Phoenix Area.
Response: Operationally, PAO's power systems are integrated. Power
marketing functions will continue to be performed separately for each
individual project. Western will continue to work with the customers in
conducting studies and evaluating other alternatives for developing a
single transmission rate for the various projects within the PAO.
Apportionment of Cost Study
Comment: The cost allocation review of historic Western O&M
expenses shows no dollars being charged against the power function on
an actual basis, which is inconsistent with the facts.
Comment: The use of historical costs are not relevant to the
Apportionment of Cost Study because the historical costs do not affect
the proposed rates.
Response: Western has revised the Apportionment of Cost Study to
reflect customer comments. The revised study does not include
historical Western O&M expenses because the historical costs do not
affect the provisional P-DP rates.
Comment: Western should adopt a reasonable or fair allocation by
splitting the difference between the historic 45/55-percent split and
the proposed 77/23-percent split or retain its historic allocation
until a detailed study can be conducted regarding what amount of actual
Western O&M should be assigned to power.
Response: Western believes the revised Apportionment of Cost Study
is an equitable and detailed study that apportions the costs between
power production and transmission service. The 45/55-percent split was
based on a study presented in the June 1979 rate adjustment brochure
for P-DP. Since that time, there has been a shift from power costs to
transmission costs, which is due to the initial investment and
irrigation investment being repaid in 1986. Thus, the majority of the
investment to be repaid is related to the refurbishment of the
transmission system. Western's future intent is to evaluate the
apportionment between power and transmission costs annually and to make
revisions to the rate design when rate adjustments occur.
Comment: Western's allocation methodology between generation and
transmission does not follow the accepted practice in expensing capital
costs and allocating other income. Western should propose a change by
allocating annual principal and interest based on generation and
transmission plant original cost depreciated.
Response: The Apportionment of Cost Study has been revised to
expense capital costs and allocate other income based on total
generation and transmission investment. However, Western also
considered the unpaid Federal investment with regard to annual
principal and interest costs. Western has determined that the unpaid
Federal investment is a transmission related cost. Therefore, annual
principal payments and interest costs for the unpaid investment will be
allocated to transmission.
Comment: The functions of power scheduling and power marketing are
power related. Furthermore, some percentage of FTEs should have been
charged against the power function.
Response: Western has revised the Apportionment of Cost Study that
is incorporated into the PRS to allocate a percentage of power
scheduling, FTEs, and power marketing to power related costs. The
percentage used for allocating these costs is based on the percentage
of total power investment to the total investment.
Comment: Western did not allocate the power and transmission
related costs to customer classes.
Response: Western allocated the power and transmission related
costs to customer classes based on power system use by each type of
customer. Users of the P-DP transmission system include customers for
(1) P-DP wholesale firm energy, (2) P-DP firm transmission service, (3)
firm transmission service for SLCA/IP, and (4) project use. Commitments
under transmission service contracts are assigned to transmission while
commitments under electric service contracts and project use are
assigned to power production. Western believes this is an equitable way
of allocating power and transmission costs among the customers.
Comment: The Allowance for Interest in Western's Apportionment of
Cost Study does not conform to Western's PRS. We understand that
Western is aware of this discrepancy, and we recommend that the proper
correction be made.
Response: Western has corrected the Allowance for Interest in the
Apportionment of Cost Study so that it conforms to the PRS.
Comment: Irrigation investment in the amount of $26.8 million has
been assigned by Western to transmission, but should be assigned to
power. The irrigation investment represents an assignment of certain
hydraulic plants to irrigation and has no relationship to transmission.
Response: The Apportionment of Cost Study uses Western's and
Reclamation's FY 1992 financial statements, budget documents, and the
Engineering Ten-Year Plan to determine the investments that are
allocated to power and the investments that are allocated to
transmission. Investments stated in Western's financial statement and
Engineering Ten-Year Plan are considered transmission investments, and
investments stated in Reclamation's financial statement and FY 1993
budget are considered power investments. Irrigation investment is in
Reclamation's financial statement. Therefore, the irrigation investment
in the amount of $26.8 million is already assigned to power in the
Apportionment of Cost Study.
Comment: An investment in FY 1990 of $3.4 million in account 331
(Hydraulic Production--Structures and Improvements) was assigned by
Western to transmission, but should be assigned to power.
Response: The investment in FY 1990 of $3.4 million in account 331
(Hydraulic Production--Structures and Improvements) is shown in the P-
DP replacement study. The P-DP replacement study incorporates both
Western's and Reclamation's investments as stated in each of the
agencies' financial statements. Western has made the assumption that
investments appearing in Reclamation's financial statements would be
allocated to power and investments appearing in Western's financial
statements would be allocated to transmission. The replacement study
was not used as a source document for the Apportionment of Cost Study.
Comment: Existing and future investments in communication
facilities have been assigned entirely to transmission. A more proper
assignment would be 50 percent to transmission and 50 percent to power
as is done by Western for the CRSP.
Response: Western has researched the possibility of assigning
communication equipment equally between power and transmission.
Communication equipment includes supervisory control and data
acquisition (SCADA), microwave system, and the joint use system. In the
Phoenix area, Reclamation and Western separately budget for microwave
systems and joint use systems. Western has determined that SCADA is a
unique investment because it has major benefits to both power and
transmission customers and it is being funded through Western's FY 1993
congressional budget. The SCADA system is, among other uses, used to
regulate power flows on the transmission lines. Because SCADA benefits
both power and transmission customers, Western has decided that 50
percent of the costs should be apportioned to power and 50 percent of
the costs consistency should be apportioned to transmission. Therefore,
the Apportionment of Cost Study has been changed to reflect the 50/50
split of the SCADA investment and associated interest expense.
Comment: Western's new PAO has been assigned entirely to
transmission. As this office is involved in both power marketing and
transmission, the cost of these facilities should be borne by both
power and transmission.
Response: This comment is incorrect in that the costs associated
with the new PAO facility have been allocated to both power and
transmission, with power being allocated approximately 16 percent of
the costs of said facility. While this may not readily be apparent at
first glance, analysis of the Apportionment of Cost Study will verify
this allocation.
In the Apportionment of Cost Study, Western first determines
whether the expenditure was funded by Western or Reclamation. All
expenditures funded by Reclamation are allocated to power. Expenditures
by Western are further analyzed to determine if they benefit only the
transmission customers or if they also benefit the power customers
(from a powerplant or power generation standpoint). To the extent the
facilities have a direct benefit to the power customers from a power
generation standpoint, a portion of the costs are allocated to power.
Western's SCADA system is an example of one of these facilities in that
although the expenditure is funded totally by Western, both the power
customers and transmission customers receive benefits from the system.
Once Western has determined the costs of those facilities which
benefit the transmission customers, a further allocation of costs is
conducted. This is due to the fact that the transmission system is
utilized both by (1) the power customers to transmit their power
entitlement from the powerplants to their loads and (2) by customers
who utilize the transmission system for bulk power transfers. It is
this allocation of costs which properly further allocates costs to
power and transmission and ensures that within the rates charged to the
power customers is a component for the use of the transmission system.
This is why the power customers are not charged a transmission charge
for their power entitlement. It is this final allocation which ensures
that the power customers are always responsible for a portion of
Western costs which are transmission related. As shown in the
Apportionment of Cost Study, the power users are allocated
approximately 16 percent of the costs of the new PAO facility.
Comment: Western assigns project use revenues as an expense offset
to power costs. Inasmuch as the delivery of this power requires use of
the P-DP transmission system, it is appropriate to assign these
revenues (expense offsets) to power and transmission in proportion to
the plant investments in each category (for step-one rates, the
allocation would be 31.66 percent to power and 68.34 percent to
transmission).
Comment: Customer believes the current allocation of both project
use revenues and project use sales is correct in Western's
apportionment study. Classification of sales (kilowatts) as power is
acceptable, provided the firm power customer classification is directly
credited with the revenues from the project use sales (kilowatts) as is
currently done in Western's Apportionment of Cost Study.
Response: Western believes the current allocation of project use
revenues is correct in the Apportionment of Cost Study. Project use
should be allocated to power because sales are also classified as
power. Further, the costs associated with project use are contained in
Reclamation's financial statement and budget documents which are also
assigned to power. Project use costs and benefits have been
consistently used in the Apportionment of Cost Study so that the
benefits will offset the costs associated with project use.
Comment: Based on restrictions on the power customers' use of
capacity paid for in the power rate and significantly better benefits
to all other users of the transmission system, we do not feel that the
allocation of costs according to customer class is correct.
Response: Western understands the power customers' concerns that
the Apportionment of Cost Study treats 1 kW of P-DP power transmitted
over the transmission system the same as 1 kW of non-P-DP power
transmitted over the transmission system, even though the P-DP power is
limited to approximately 56 percent capacity factor. However, Western
believes that because the customers have complete flexibility to
schedule their power and energy when they want, Western transmission
must be available to handle the desired transaction. Western bases the
Apportionment of Cost Study on the kW of ``reservation'' the customers
have for use of the system and not on the actual kWh usage of the
system. From this perspective, power customers and transmission
customers alike pay to have the transmission system reserved for their
use, regardless of the actual system use.
Comment: Western should consider a phase-in of what would be a
significant shift in allocation of costs from transmission to
generation if the cost apportionment study is adapted.
Response: In response to the customer comments, Western has decided
to implement stepped rates for the provisional P-DP rate schedules. The
first steps of the provisional rates are effective from FY 1994-95 and
the second steps are effective for FY 1996-98. Step-one rates reflect
only the replacements and additions proposed by Western for FY 1994-95.
Step two rates reflect the replacements and additions for FY 1996
through the end of the study period. Implementing stepped rates will
lessen the impact on the customers by allowing them to phase-in the new
rates.
Calculation of Interest During Construction
Comment: Western should reexamine the procedure for utilizing the
interest rates in effect at the inception of the project and change the
regulation accordingly. Western's definition of start of construction
and charging of IDC should be revised to reflect FERC policy.
Comment: Western is using the wrong interest rates on replacements
and additions. The interest rate in effect for each year of a project's
appropriation should be used and a weighted average rate established on
completion of the project.
Response: Western's policy is to utilize the interest rate in
effect at the inception of the project and Western believes this
accurately reflects FERC policy and is in accordance with DOE Order No.
RA 6120.2. IDC accumulates at the appropriate effective interest rate
for a replacement or addition when the first direct cost (FERC Accounts
350 and above) is incurred to initiate construction or replacement.
This interest rate remains constant with the investment. IDC terminates
at the end of the FY in which the facility is placed in service. DOE
Order No. RA 6120.2 states that the interest rate to be used for
computing interest during construction shall be the yield rate during
the FY in which construction is initiated. Therefore, Western does not
believe that a weighted average reflects FERC policy or is in
accordance with DOE Order No. RA 6120.2.
Comment: Western is using the wrong interest rates on replacements
and additions.
Response: Western uses the most current yield interest rates as
defined by the Department of the Treasury for each FY. This is in
accordance with the formula set forth in DOE Order No. RA 6120.2,
paragraph 11(b).
Comment: It was suggested that Western use the most current
interest rate.
Response: At the time of the comment forum, Western was using the
most current interest rate of 8.5 percent as defined by the Department
of the Treasury. Since then, Western has revised the Ratesetting PRS to
reflect the interest rate calculated for FY 1992, which is 7.875
percent. As a result, interest expense in future years has decreased.
Rate Design
Comment: In its revised PRS of June 1993, Western has continued to
use the wheeled kW from early 1992 in the design of its currently
proposed transmission rate. However, there have been increases to
Western's transmission capacity under contract, and further increases
are currently known.
Response: Western will use the most current contractual amount of
firm transmission in kW for the design of the firm transmission rate.
Therefore, the number of kW will increase from 1,411,228 to 1,508,676
in step one of the P-DP transmission rate. The number of kW will
increase to 1,584,150 in step two of the P-DP transmission rate.
Comment: It is improper to burden the existing transmission
customers with the cost of new capacity, and an allowance for increased
contracted kW would remedy somewhat this inappropriate burden.
Response: The only additional transmission facility being added to
the system is the Mead-Basic #2 line. Further studies need to be
completed to determine what, if any, additional transmission capability
is available to the system as a result of the installation of this
transmission line. In the event Western adds additional transmission
capability to the system and contracts for the additional capacity,
this would be reflected in the Apportionment of Cost Study for future
PRSs.
Comment: Western should implement multistep rates, designed to meet
annual financial obligations without prepayment of debt. A multistep
rate would be designed to meet annual financial obligations.
Response: FERC approves rates for a 5-year period. These rates have
to produce adequate revenues that will recover all annual costs and
will repay project investments in no longer than a 50-year period.
Rates cannot be approved by FERC beyond the 5-year window. If multistep
rates were designed outside the 5-year window, then the rates within
the 5-year window would not adequately recover all costs and repay
project investment over a 50-year period. Thus, the requirements of DOE
Order No. RA 6120.2 would not be met. However, within the 5-year
period, Western has decided to implement a two-step rate process, so
the customers can phase-in the significant rate increase.
Comment: The rate design method does not reflect or adjust to
changes in the cost of service for each customer classification which
will occur over time. Western is only applying the results of the
Apportionment of Cost Study to the incremental revenue requirement
above that which can be met by the current rates. The net result is
dilution of the transmission contractor's financial obligation at the
expense of the power customers.
Comment: Western compounds its errors by allocating only the
incremental part of the rate increase to power and transmission. The
rate design should be based upon total revenue requirements, not
incremental revenue requirements.
Response: Western understands the negative aspects of only
allocating the incremental part of the rate increase between power and
transmission. However, the customer is assuming that the past
apportionment of 55 percent for power and 45 percent for transmission
was incorrect. Western believes the last apportionment between power
and transmission is correct, meaning that the rate design should be
incremental. Each year, Western will perform an Apportionment of Cost
Study to stay abreast of the incremental change from year to year. The
reason for the large incremental change from power to transmission is
that the original project has been fully repaid and the transmission
system is deteriorating and must be refurbished.
Replacements and Addition Activities
Comment: Errors may exist in the assignment of replacement and
addition costs between P-DP customers and Federal agencies. Western did
not examine other sources of funding.
Comment: The proposed increase is excessive since it includes
extensive refurbishment in the Phoenix Area which does not support the
path over which service is provided.
Response: The need for projected replacements and additions has
been previously examined and justified through the O&M and engineering
budget process. Projected replacements and additions have been
identified in Western's Engineering Ten-Year Plan, along with Western's
FY 1993 Budget documents. Further, facility development reports have
been developed which analyze the costs and benefits to Western.
Although Western receives some funding through trust and reimbursables
the majority of the costs that benefit the system as a whole are placed
into the rate base. Western has included the customers in the planning
process. This will allow the customers to help Western examine sources
of funding and plan extensive refurbishment in the Phoenix Area.
Comment: When did the replacement and addition program begin and
what is the current status of the program?
Response: During FY 1991, Western developed the Engineering Ten-
Year Plan which was a planning tool for ongoing replacement and
addition activities. In June 1993, Western invited the customers to
participate in developing the engineering 10-year planning process.
Western is currently working with the customers in updating and
revising the Engineering Ten-Year Plan. It is Western's intention to
update and evaluate the Engineering Ten-Year Plan annually with the
customers.
Comment: Western has based its decisions to replace facilities and
equipment on the age of the facility and equipment or on Western's
desire to try out new equipment technologies. The replacement and
addition program was not planned, designed, scheduled, or maintained to
best serve the customers. There is concern on how well Western has
managed its program.
Comment: Western has not designed facilities in a cost-effective
manner.
Comment: Concerning its replacement and addition program (program),
Western did not (i) perform appropriate planning analysis, (ii) assess
program impact on rates prior to implementation, (iii) inform customers
of program, (iv) seek input from customers, or (v) minimize magnitude
of program. Western has not attempted to schedule or prioritize work to
minimize rate impact.
Response: Western utilizes accepted utility design standards and
detailed engineering economic studies in determining, planning, and
executing construction and replacement projects. These standards and
studies are described in Western's FDRs for each major construction
project. Furthermore, the purpose of the Engineering Ten-Year Plan is
to effectively design, plan, prioritize, schedule, and analyze rate
impacts on all the Phoenix Area Projects. Western believes that future
rate impacts are minimized and costs can be controlled through this
process. Western is now including the customers in the planning process
so they are informed and may provide input on future construction
activities. By including the customers in this process, Western will
minimize rate impacts and meet customers' needs.
Comment: A fixed amount for replacements of $4.3 million in future
FY 1998-2047 cannot be representative of future replacements when
practically the entire system will have been replaced by 1998.
Comment: Western should make a commitment to limit replacements to
$4.3 million or less after 1997 unless authorized by the working
committee.
Response: Western believes the $4.3 million average is a good
representation of the future replacement costs and is based on the
replacement program which reflects historic experience and service
lives of project equipment and facilities. Western cannot commit to a
fixed amount when the amounts are based on actual experience and an
annual budget document, which change over time.
Comment: Western optimistically forecast savings and did not
consider the full and true cost of its 5-Year Plan, phase two of the
Phoenix Office, plus the total replacement and addition investment
levels, to determine the overall impact on P-DP rates.
Response: Western believes that the benefits of consolidation are
just beginning to be recognized and once the consolidation process is
completed, there will be additional long-term savings. Prior to the
decision to consolidate the Phoenix District Office with the Boulder
City Area Office, Western conducted a cost/benefit analysis that
included replacement and addition investments. This study analyzed the
costs and benefits of five different options of which the option to
consolidate the Phoenix District Office and the Boulder City Area
Office indicated the highest cost savings. This option also indicated
the lowest rate impacts. The study concluded (among other things) that
planned construction at Phoenix can be modified and expanded at a
reasonable cost to accommodate the Area functions and increase office
space. However, it also indicated that there would be disruption of
continuity for up to 2 years and that there would be additional
construction costs.
Comment: Western's replacement and additions program is not
justifiable.
Comment: Western is attempting to replace a large portion of the
facilities over a 10-year period. The replacement costs and the
administration and general costs of administering the replacement work
peaked, making the rate impact abnormally high. It is suggested that
Western attempt to select a replacement period of 15 to 20 years as
compared to the Engineering Ten-Year Plan.
Comment: Western has not explained or justified the astronomical
increase in replacements from less than $2 million on average for the
past 10 years to amounts averaging over $14 million for the years 1993
through 1998.
Comment: The rate proposal offers considerable discretion in the
replacement budget area. This includes the time period over which the
expenditure needs to be made and the necessity of certain expenditures.
Response: The justification for the replacement and addition
program is that the P-DP is over 50 years old and is in the process of
a major refurbishment and replacement program. A large portion of the
system is deteriorating to the point where safe and continued operation
to all customers is jeopardized. The Engineering Ten-Year Plan analyzes
the activities with considerable scrutiny over a period of 10 years and
will be updated annually. While developing the Engineering Ten-Year
Plan, Western deferred certain replacement and addition activities
until a later date. Overall, the Engineering Ten-Year Plan resulted in
a refurbishment and replacement program that will improve reliability,
improve personnel safety, increase capacity, and replace out-of-date
equipment that cannot be repaired.
Comment: The replacement expenditures after the 5-year evaluation
period do not reflect the replacements scheduled during the evaluation
period. As a result, the PRS may include costs for replacements during
the study period which will actually be replaced during the evaluation
period.
Response: The replacement study projects replacements after the 5-
year evaluation period based on the total plant investment as of FY
1991. Projections during the cost evaluation period (FY 1994-98) are
based on the replacements indicated in the Engineering Ten-Year Plan.
Replacements projected during the cost evaluation period will not be
duplicated in out years, as long as the replacement is made relatively
close to the end of the equipment's service life. The replacement study
is based on historic experience and service lives of each type of
equipment and has proved to be an effective tool for projections.
Comment: It appears to the customer that Western is, in effect,
double covering future replacement costs by including the $4.3 million
annual replacements estimate, notwithstanding the Engineering Ten-Year
Plan, which includes a full planning horizon 5 years beyond the 5-year
ratesetting period. The $4.3 million annual replacements projection
should be eliminated from this rate before filing with FERC, in
reliance upon the Engineering Ten-Year Plan process and as evidence of
Western's full-faith commitment with its customers to the Engineering
Ten-Year Plan concept.
Comment: Western has the perfect opportunity here to submit this
rate to FERC without the $4.3 million estimate on replacements in the
future with the Engineering Ten-Year Plan as the appropriate rationale
for any deviation from DOE Order No. RA 6120.2 that FERC might consider
it to be.
Comment: While it is the general intent of DOE Order No. RA 6120.2
that Western include allowances for replacements for the entire study
period of the PRS, DOE Order No. RA 6120.2 also permits a deviation
from this requirement in paragraph 1. It is recommended that Western
adopt any reasonable approach to mitigate this large increase. FERC
addressed the matter of replacements in Docket EF89-5041-000. While we
may not necessarily agree with the FERC order in its entirety, we
believe that Western has the ability to deviate from the requirements
of DOE Order No. RA 6120.2. Therefore, Western should omit from its
proposed PRS the currently proposed allowances for replacements in the
amount of $217 million ($4.3 million per year) for years 1998-2047. The
use of an average amount has helped minimize the rate impact.
Response: In the recent past, FERC has ruled on a P-DP rate
adjustment that the PRS should show that revenue produced by the
provisional P-DP rates is adequate to pay all of the project's annual
costs, repay investment with interest of the project, and provide for
payment of replacement costs over the life of the project. Docket No.
EF 89-5041-000 states:
Nevertheless, WAPA has failed to recognize replacement costs
that will be incurred between 1993 and 2042. The draft PRS that WAPA
provided in response to staff's request provides an indication of
the extent of these replacements and their considerable costs.
WAPA has neither complied with Order No. RA 6120.2 nor asserted
any basis upon which the Commission could find WAPA's interim rates
``consistent with sound business principles'' or ``sufficient to
recover the costs of producing and transmitting electric energy . .
. .'' Under these circumstances, the Commission will exercise its
delegated authority to remand the interim Parker-Davis rates and to
direct WAPA either to: 1) file substitute rates and accompanying
documents in accordance with the terms of this order; or 2)
alternatively, refile its proposed rates and clearly demonstrate
that the omission of the replacement costs discussed herein from the
proposed rates and the PRS has been ``specifically approved by the
Secretary of Energy, authorized by statute, or identified and
explained in a transmittal memorandum or in a footnote to the
reports.''
Therefore, Western cannot omit the allowances for replacements in
the amount of $217 million ($4.3 million per year) for years 1998-2047.
The use of an average amount has substantially mitigated much of the
impact on rates.
Western is working with the customers on a review of the
Engineering Ten-Year Plan of capital additions and replacements and of
the appropriateness of its incorporation into the PRS. Specifically,
the customers and Western will examine the use in the PRS of
projections of future replacements from the Engineering Ten-Year Plan
versus projections of replacements from the Replacement Study portion
of the PRS. Western and its customers will examine which future
replacements projection and revenue requirements are most appropriate
for reliable operation of the Federal system and setting rates.
Comment: Customer is concerned about the high concentration of
replacement and addition costs in FY 1994 and FY 1995 within the rate
period. History dictates that Western will, in fact, not be able to
manage or execute those levels of expenditures in short periods of
time. Please reexamine the expenditures schedule before the rate is
finalized to avoid any unnecessary pinch-point resulting from
unrealistic projections.
Response: Western has reexamined the replacement costs and believes
the costs used in the PRS for replacements in FY 1994 and FY 1995 are
appropriate and are the best estimates to date. Western hopes to work
through the engineering 10-year planning process with the customers to
reexamine the expenditures schedule. This will not be completed before
the rate process is completed. However, Western has examined the pinch-
point in the PRS. The step-one rate increase is being set to meet
annual expenses and interest expense. The step-two rate increase is
being set to meet required payments needed to fully repay investment.
Purchased Power
Comment: Purchased power costs do not reflect planned flow releases
from upstream reservoirs (i.e., $700,000 in purchased power costs
should be eliminated after FY 1993). On April 8, 1992, Reclamation
prepared a forecast of water releases through Hoover Dam. This forecast
is based upon a consumptive water use downstream of Hoover Dam of 7.5
MAF and a delivery requirement of 1.5 MAF to Mexico. From 1993-97,
these figures match the flows in 1987, and in 1987, P-DP did not
purchase power. P-DP generated 482,875,918 kWh in excess of contract
requirements.
Response: Western has certain contractual capacity and energy
commitments to the P-DP contractors, regardless of the forecasted water
releases from Hoover Dam, the upstream water supplier to Parker and
Davis Dams. Western calculates the purchased power costs based upon a
comparison of Reclamation's schedule of downstream water releases with
the projected energy schedules of the P-DP contractors. While the total
water releases, on an annual basis, may be sufficient to generate all
of the energy requirements of the P-DP on an annual basis, the real-
time water release may not match the real-time energy schedules and
power purchases must be made. The FY 1993 budget reflects Western's
projection that approximately $700,000 per year would need to be
budgeted to assure power deliveries to the P-DP contractors. Since the
derivation of the FY 1993 budget, Western has increased this projected
expenditure to approximately $2.3 million.
Comment: Western should reduce the projected expenditures for the
period May 1993 through September 1993 to correspond to the average of
previous years.
Response: Western has changed the PRS to show the most current
purchased power expense for FY 1993, which reflects the flow
restrictions last year. This purchased power expense has been reduced
to $5 million in FY 1993 as compared to the $6.5 million previously
shown in the addendum to the May 1992 customer brochure dated June
1993.
Comment: Please extend the schedule for repayment of capitalized
purchased power costs and use this tactic, along with other adjustments
to FY 1994 and FY 1995, to reduce step one for P-DP purchased power
costs.
Response: Western has determined through analyzing the PRS that the
repayment schedule of the capitalized purchased power cost, which is a
loan to meet annual expenses, is not setting the step-one rate. The
step-one rate is being set by interest expense in FY 1995. If repayment
is deferred, the interest expense actually increases. The PRS is
designed to pay interest expense before it repays any loans. Western
believes the Ratesetting PRS solves for the lowest rate possible in
both steps and is in accordance with sound business principles.
Comment: Western should reexamine the projections for purchased
power made during the period of January through March and in September.
Many of Western's customers that serve primarily agricultural loads
will have reduced loads during these periods. Western has previously
facilitated exchanges in such situations to reduce the need for
purchased power.
Response: Western is willing to work with the customers in resource
planning initiatives and realizes the importance to mitigate purchased
power. Western has attempted to use resource integration by exchanging
energy efficiently to support customer loads. However, this would only
reduce purchased power expense if a majority of the P-DP customers
could derive load profiles that matched river regulation restrictions.
Comment: Western should project some level of nonfirm sales in the
upcoming years based on historic water demand and projected water
supply figures from Reclamation. A prudent projection of those
revenues, including revenues that will be available from mothballing
the Yuma desalter, should be projected.
Response: In the Ratesetting PRS, nonfirm sales are projected based
on a historical average of revenue earned from nonfirm sales.
Currently, Western is unsure how the mothballing of the Yuma desalter
will impact revenues, energy, and transmission. Future decisions will
be reflected in future rate actions.
Comment: Customers would be better served if the P-DP contracts
were amended to provide an option to the contractors for Western to
purchase firming energy on the contractor's behalf, or for Western to
provide only the energy generated by the P-DP project itself.
Response: The Phoenix Area is receptive to meeting with the
customers to discuss possible options. Western believes, however, that
any course of action chosen should be in the best interest of all
parties and should be as easy to implement as possible in order to
minimize the costs of administration.
Working Committee
Comment: Western should cooperate in the formation of a process to
allow customer review and input to Western's work plans projected 5 to
10 years in the future for O&M, replacements, and additions at an early
enough stage of the planning cycle to have an impact. The creation of
an Engineering and Oversight Committee would provide for a safeguard
against overcollection, inflated estimates of projected expenditures,
an organized dialogue with its customers, and prevent the reoccurrence
of past overspending in the future.
Comment: Western should support a customer and agency working
committee. Included in the working committee should be objectives and
criteria that relate to balancing the goal of safe and reliable
operations with the goal of cost containment and other economic
efficiencies. A year ago, the Arizona Power Authority endorsed a
proposal to create and empower a P-DP Engineering and Oversight
Committee as the structure and process for working toward price
stability. Since then, with customer involvement, Western has started
two programs that provide promise for working toward the price
stability goal--the Engineering Ten-Year Plan and the transmission
planning system.
Western should continue the formalization of an engineering 10-year
planning process involving the P-DP customers as initiated by Western
during the spring of 1993.
Response: Western supports some type of a customer and agency
operational working committee. Western is committed to working closely
with the customers in the development of a customer/agency operational
working committee and has, in fact, initiated a procedure for allowing
its customers more advance input into the planning process. Western has
asked the customers for their help in developing a current Engineering
Ten-Year Plan. This has allowed Western to organize dialogue with the
customers and has allowed the customers to provide input on future
construction activities. Western is currently working with the
customers to design criteria that will balance the goal of safe and
reliable operations with the goal of cost containment. Improved
efficiencies will be a result of including the customers in the
engineering 10-year planning process. Further, Western believes that
the participation of the customers in developing the Engineering Ten-
Year Plan and transmission planning system, also referred to as the
joint-use transmission system, is just the beginning of involvement and
partnerships Western is hoping to achieve with its customers.
Economic Issues
Comment: Western should consider emergency cost-cutting measures to
help Arizona customers and small utilities through these economic
times.
Comment: Western should consider the plight of irrigation customers
when they pass the rate increase costs on to them.
Comment: At this time, the cost of significant replacements and
additions on the P-DP cause tremendous strain on Buckeye and its
customers.
Comment: Western should consider the effects of the rate increases
on the agricultural economy in Arizona.
Comment: Western should postpone the implementation of the rate
increase.
Comment: Western's PAO must begin to recognize its responsibilities
to consumers of Arizona, California, and Nevada and must not forget its
mission is to market and deliver low cost Federal hydropower to
preference customers.
Comment: There is concern about the cost increases in
transmission's O&M, replacements, and additions that are substantially
greater than the rate of inflation. Based on decisions that have been
made, Western should request establishing and empowering a process for
control of such costs in the future.
Comment: It is requested that Western consider every possible
alternative which will reduce the need for such significant rate
increases.
Response: Western has reviewed its O&M and replacement costs and
believes that the costs have been justified. While Western is
sympathetic to the current financial plight of a number of the
customers with large agricultural loads, Western and the Bureau believe
the replacement and addition costs cannot be deferred to a later date
without jeopardizing safety and reliability. Western realizes that
replacements and additions exceed the rate of inflation. However,
Western cannot allow the Parker-Davis facilities to deteriorate to a
point where safe and continued operation to all customers is
jeopardized. Western is continuing to look at both its O&M and
construction plans to determine what, if any, expenditures can be
avoided or delayed, without sacrificing service to its customers.
Western believes the mission to market and deliver low-cost Federal
hydropower to all customers has not been neglected. Western is
committed to work with its customers to ensure that all entities are
satisfied regarding the O&M and replacement expenditures. Western,
along with the customers, will continue to review and revise O&M and
replacement costs which will meet the needs of the customers and the
needs of the P-DP system.
General Rate Issues
Comment: To date, much of the frustration of the customers with
Western's ratesetting process results from not understanding Western's
numbers, or where they come from, or the inconsistent sources used
during the process.
Response: The numbers used in the PRS are consistent with the
Engineering Ten-Year Plan and with the FY 1993 budget. Western hopes
that involving the customers in the engineering 10-year planning
process will result in a better understanding of how the numbers used
in the PRS are derived.
Comment: Western should use the current budget in the current PRS,
and use the Engineering Ten-Year Plan in future PRSs.
Comment: The FY 1992 Engineering Ten-Year Plan Western is using
significantly overstated Parker-Davis expenditures for FY 1993 and FY
1994, blessed with the hindsight of an actual 1993 budget and a
requested FY 1994 budget. The rates should reflect these later
realities.
Response: Western chose to use the Engineering Ten-Year Plan in the
Ratesetting PRS because it was the best information available at the
time. However, the PRS relies on several pieces of data. For instance,
during the cost evaluation period, the replacements and additions from
the Engineering Ten-Year Plan were all in the FY 1993 congressionally
approved budget. The Engineering Ten-Year Plan varies from the FY 1993
congressionally approved budget in timing of completion of projects and
amounts to be spent in FY 1994-98. Western is currently meeting with
the customers to develop a revised Engineering Ten-Year Plan in the
future that will incorporate customer input. Western plans on using the
Engineering Ten-Year Plan as a tool in developing the budgets so that,
in the future, the PRS will be based on budget documents founded in the
Engineering Ten-Year Plan.
Comment: Clearly the use of the Engineering Ten-Year Plan is a
deviation from the requirements of DOE Order No. RA 6120.2. It is for
the simple reason that it does not, and indeed is not necessarily
intended to, reflect only investment costs ``for which Congress has
appropriated funds for construction and which will be in service within
the cost evaluation period.'' (DOE Order No. RA 6120, paragraph 10 k)
As such a deviation, its use will be required to be accompanied by a
statement disclosing and justifying the deviation. (DOE Order No. RA
6120.2, paragraph 13.) Such justification must be included in the
transmittal memorandum from the Secretary to FERC or in a footnote to
the reports that accompany such transmittal.
Response: All of the investments in the Ratesetting PRS are
authorized power system facilities for which Congress has appropriated
funds for FY 1993 construction, and which will be in service within the
cost evaluation period. Therefore, Western believes it has complied
with DOE Order No. RA 6120.2. The Engineering Ten-Year Plan was used to
determine if the investments in the FY 1993 Budget were still planned
to be in service within the cost evaluation period. The Engineering
Ten-Year Plan was a better source of data to use in terms of timing of
completion of construction activities and the dollars that will be
spent in years 1994-98. The appropriated budget amounts for FY 1993
were changed only to match the most current budget information. Western
believes that the Engineering Ten-Year Plan was the best data available
at the time.
Comment: Reclamation should increase the rate for project use.
Response: Reclamation is currently reviewing the accuracy of the
project use rates. If it is determined that the project use rates
require adjustment, Reclamation will take the necessary steps to
implement a change in these rates. The resulting change, if any, will
be reflected in a future PRS conducted by Western.
Comment: Western continues to be out of compliance with DOE Order
No. RA 6120.2 which requires audits at least once every 2 years.
Response: Western is in compliance with DOE Order No. RA 6120.2 in
that it has annual audits. Western has either had an annual
consolidated Western-wide audit or project-specific audit which both
meet the criteria of DOE Order No. RA 6120.2. Currently, P-DP is
undergoing a project-specific audit.
Comment: There is concern in justifying this rate increase in light
of WAPA's own admission that the existing rate is adequate to fully
recover costs and meet repayment requirements for at least the next 5
years. The pinch-point methodology used in the PRS for determining the
rates is doing the customers a disservice.
Comment: The establishment of the current rate based upon
anticipated revenue requirements in FY 2047 is unreasonable.
Response: P-DP's PRSs are required to repay each dollar of
investment with interest within a period not to exceed 50 years. The
use of the pinch-point methodology and the longstanding practice of
repaying investment with interest within 50 years are justified and
identified in DOE Order No. RA 6120.2. Section 12 of the Order
describes the guidelines for the cost recovery criteria which is what
the pinch-point methodology accomplishes. The pinch-point in the
Ratesetting PRS is FY 2047. This pinch-point is due to a required
payment needed to fully repay an investment within a 50-year period.
Comment: There is disagreement with Western's classification
process for capitalizing versus expensing. O&M expense costs should be
classified as a capital cost and amortized over the expected service
life of the facility involved. Specifically, vehicle expenditures were
classified as expense rather than capitalized.
Response: Vehicle expenditures were expensed rather than
capitalized and it is Western's policy to expense minor replacements
($5,000 or less) and capitalize major replacements (over $5,000).
However, the particular budget document that is being questioned
contains a significant number of (i) expendable communication items and
(ii) electrical test equipment, in addition to several vehicles. The
service lives of the communication items and test equipment is
sufficiently short enough to justify expensing the costs of said
equipment. Due to the fact that only a small portion of the costs of
the budget document were related to the purchase of vehicles, a
decision was made to expense the entire budgeted amount.
Comment: Customer feels Western should withdraw its proposal
regarding the expansion of its area load control boundaries to the
Basic Substation. They feel Western has no justification for this
proposal and there are no benefits.
Response: Western does not believe this comment pertains to, or has
any impact on, the P-DP provisional rates. However, Western has
withdrawn the proposal to expand Western's load control boundaries to
Basic Substation.
Comment: Western is accelerating repayments to periods far shorter
than the average or expected service life of the facilities involved.
Capital investments are being amortized over unduly short periods.
Response: The PRS program is designed to solve at the lowest rate
possible that is consistent with sound business principles. The PRS
program is designed to calculate a rate over a 50-year period. However,
the program will repay investment in a shorter period of time to
minimize interest expense, providing revenue is available to accomplish
this. If capital investment repayment was deferred, then interest
expense would increase, which could result in a higher rate.
Comment: P-DP has an additional 30 MW of firm capacity because
Hoover is providing the P-DP spinning reserves. However, Western should
not transfer revenue to the Hoover project with regard to spinning
reserves.
Response: Western has researched this matter thoroughly and can
find no evidence that Hoover is providing spinning reserves to the P-
DP. Although the Consolidated Marketing Plan anticipated that an
additional 30 MW of P-DP capacity would be available for sale as a
result of consolidated operations within the Boulder City Area (now the
Phoenix Area), spinning reserve requirements have not changed. The PAO
operations department, in conjunction with a consultant on loan from
MWD, is continuing to investigate this issue. Any identified benefits
to the P-DP will be reflected in future PRSs.
Comment: Customer objects to the continuance of Western's 1989
decision to change the costs for using the Hoover-Basic and Hoover-
Mead-Basic transmission lines and Basic Substation from a facilities
use charge to the postage-stamp rate for the entire P-DP transmission
system.
Western should revise its proposed P-DP rate adjustments in a
manner that restores the Hoover-Basic and Hoover-Mead-Basic
transmission lines and the Basic Substation to a facilities use charge
which covers the actual costs associated with use of these facilities.
Response: Western does not believe that this comment pertains to or
impacts the P-DP provisional rates.
Comment: The customers are concerned that they may be paying twice
for the same service since Mead is already part of the P-DP. Western is
already charging Edison $0.624/kW/year for use of the substation under
their existing agreement.
Response: Western has reviewed the provisions concerning the Mead
facilities charges in the P-DP transmission agreements and has
determined that there is no double accounting to the customers for the
same capital facilities. In determining Mead facilities charges to
Parker-Davis transmission customers, the costs of the Mead facilities,
replacements, and O&M expenses are first allocated to the P-DP based
upon the number of functions used. This allocation is further allocated
based upon the transmission capacity as stated in the contracts.
Environmental Evaluation
In compliance with the National Environmental Policy Act of 1969
(NEPA) 42 U.S.C. 4321 et seq.; Council on Environmental Quality
Regulations (40 CFR Parts 1500-1508); and DOE NEPA Regulations (10 CFR
Part 1021), Western has determined that this action is categorically
excluded from the preparation of the environmental assessment or EIS.
Executive Order 12866
DOE has determined that this is not a significant regulatory action
because it does not meet the criteria of Executive Order 12866, 58 FR
51735. Western has an exemption from centralized regulatory review
under Executive Order 12866; accordingly, no clearance of this notice
by OMB is required.
Availability of Information
Information regarding these P-DP rate adjustments, including PRSs,
comments, letters, memorandums, and other supporting material made or
kept by Western for the purpose of developing the P-DP power rates, is
available for public review in the Phoenix Area Office, Western Area
Power Administration, Office of the Assistant Area Manager for Power
Marketing, 615 South 43rd Avenue, Phoenix, Arizona 85009-5313; Western
Area Power Administration, Division of Marketing and Rates, 1627 Cole
Boulevard, Golden, Colorado 80401-3398; and Western Area Power
Administration, Office of the Assistant Administrator for Washington
Liaison, Room 8G-061, Forrestal Building, 1000 Independence Avenue SW.,
Washington, DC 20585.
Submission to Federal Energy Regulatory Commission
The P-DP rates herein confirmed, approved, and placed into effect
on an interim basis, together with supporting documents, will be
submitted to FERC for confirmation and approval on a final basis.
Western understands that the effective date is less than 30 days after
the Deputy Secretary places the provisional rates into effect on an
interim basis. A waiver of Sec. 903.21(b) was requested to avoid
financial difficulties, and I concur in that waiver.
Order
In view of the foregoing and pursuant to the authority delegated to
me by the Secretary of Energy, I confirm and approve on an interim
basis, effective February 1, 1994, P-DP Rate Schedules PD-F4 for firm
power, PD-FT4 for firm transmission, PD-NFT4 for nonfirm transmission,
and PD-FCT4 for firm transmission service for SLCA/IP. The P-DP rate
schedules shall remain in effect on an interim basis, pending FERC
confirmation and approval of them or substitute rates on a final basis,
through January 31, 1999 or until superseded.
Issued in Washington, DC, January 6, 1994.
William H. White,
Deputy Secretary.
Rate Schedule INT-FT1
United States Department of Energy, Western Area Power
Administration, Pacific Northwest-Pacific Southwest Intertie
Project Schedule of Rates for Firm Transmission Service
Effective
Step One: The first day of the first full billing period beginning
on or after August 1, 1993.
Step Two: The first day of the first full billing period beginning
on or after October 1, 1995, and will remain in effect through July 31,
1998, until superseded, whichever occurs first.
Available
Within the marketing area served by the Pacific Northwest-Pacific
Southwest Intertie Project.
Applicable
To firm transmission service customers where capacity and energy
are supplied to the Pacific Northwest-Pacific Southwest Intertie
Project (AC Intertie) system at points of interconnection with other
systems and transmitted and delivered, on a bidirectional basis, less
losses, to points of delivery on the AC Intertie system specified in
the service contract.
Character and Conditions of Service
Alternating current at 60 Hertz, three-phase, delivered and metered
at the voltages and points of delivery established by contract.
Rate
Step One: Firm Transmission Service Charge: $4.46 per kilowatt per
year for each kilowatt delivered at the point of delivery, as
established by contract: payable monthly at the rate of $0.372 per
kilowatt.
Step Two: Firm Transmission Service Charge: $8.01 per kilowatt per
year for each kilowatt delivered at the point of delivery, as
established by contract: payable monthly at the rate of $0.6675 per
kilowatt.
Adjustments
For Reactive Power
None. There shall be no entitlement to transfer of reactive
kilovolt-amperes at points of delivery, except when such transfers may
be mutually agreed upon by contractor and contracting officer or their
authorized representatives.
For Losses
Capacity and energy losses incurred in connection with the
transmission and delivery of capacity and energy under this rate
schedule shall be supplied by the customer in accordance with the
service contract.
Billing for Unauthorized Overruns
For each billing period in which there is a contract violation
involving an unauthorized overrun of the contractual firm power and/or
energy obligation, such overrun shall be billed at 10 times the above
rate.
Rate Schedule INT-NFT1
United States Department of Energy, Western Area Power
Administration; Pacific Northwest-Pacific Southwest Intertie
Project
Schedule of Rates for Nonfirm Transmission Service
Effective
Step One: The first day of the first full billing period beginning
on or after August 1, 1993.
Step Two: The first day of the first full billing period beginning
on or after October 1, 1995, and will remain in effect through July 31,
1998, until superseded, whichever occurs first.
Available
Within the marketing area served by the Pacific Northwest-Pacific
Southwest Intertie Project.
Applicable
To nonfirm transmission service customers where capacity and energy
are supplied to the Pacific Northwest-Pacific Southwest Intertie
Project (AC Intertie) system at points of interconnection with other
systems and transmitted and delivered, on a bidirectional basis, less
losses, to points of delivery on the AC Intertie system established by
contract.
Character and Conditions of Service
Alternating current at 60 Hertz, three-phase, delivered and metered
at the voltages and points of delivery established by contract.
Rate
Step One: Nonfirm Transmission Service Charge: 1.00 mills per
kilowatthour of the scheduled or delivered kilowatthours at the point
of delivery, established by contract: payable monthly.
Step Two: Nonfirm Transmission Service Charge: 1.52 mills per
kilowatthour of the scheduled or delivered kilowatthours at the point
of delivery, established by contract: payable monthly.
Adjustments
For Reactive Power
None. There shall be no entitlement to transfer of reactive
kilovolt-amperes at points of delivery, except when such transfers may
be mutually agreed upon by contractor and contracting officer or their
authorized representatives.
For Losses
Capacity and energy losses incurred in connection with the
transmission and delivery of capacity and energy under this rate
schedule shall be supplied by the customer in accordance with the
service contract.
[FR Doc. 94-2730 Filed 2-4-94; 8:45 am]
BILLING CODE 6450-01-P
This is a copy of a public record, reproduced as it was published. It is not legal advice, and it may not be the version a court would rely on. Check the official source before you cite it.