[Federal Register Volume 62, Number 228 (Wednesday, November 26, 1997)]
[Notices]
[Pages 63150-63157]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 97-31074]
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DEPARTMENT OF ENERGY
Western Area Power Administration
Parker-Davis Project Rate Adjustment; Notice of Rate Order No.
WAPA-75
AGENCY: Western Area Power Administration, DOE.
ACTION: Notice of rate order.
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SUMMARY: Notice is given of the confirmation and approval by the Deputy
Secretary of the Department of Energy (DOE) of Rate Order No. WAPA-75
and Rate Schedules for Wholesale Firm Power Service (PD-F6) , Firm
Transmission Service (PD-FT6), Firm Transmission Service of Salt Lake
City Area Integrated Projects Power (PD-FCT6), and Nonfirm Transmission
Service (PD-NFT6) placing into effect the rate methodology for
determining rates for existing Parker-Davis Project (P-DP) contractors
of the Western Area Power Administration (Western) on an interim basis.
The rate methodology will remain in effect on an interim basis until
the Federal Energy Regulatory Commission (FERC) confirms, approves, and
places it into effect on a final basis or until superseded.
DATES: Rate Schedules PD-F6, PD-FT6, PD-FCT6, and PD-NFT6 will be
placed into effect on an interim basis on the first day of the first
full billing period beginning on or after November 1, 1997, and will be
in effect until FERC confirms, approves, and places the rate schedules
into effect on a final basis for a 59-month period, or until the rate
schedule is superseded.
FOR FURTHER INFORMATION CONTACT: J. Tyler Carlson, Regional Manager,
Western Area Power Administration, Desert Southwest Regional Office,
P.O. Box 6457, Phoenix, AZ 85005, (602) 352-2453, or Joel K. Bladow,
Assistant Administrator for Power Marketing Liaison, Room 8G-027, 1000
Independence Avenue, SW., Washington, DC 20585, (202) 586-5581.
SUPPLEMENTARY INFORMATION: The proposed rate methodology is the result
of Western, the Bureau of Reclamation, and existing P-DP customers
working together to develop a methodology that would recover the
project costs and accommodate advance funding for P-DP expenses. The
changes made to the P-DP rate methodology are outlined as follows. The
first change concerns the Cost Apportionment Study. The study, which
demonstrates the distribution of costs between generation and
transmission, has been changed as follows: (1) the Priority Use Power
(PUP) contractors' delivery commitments are now included in the total
amounts reflected in the generation and transmission delivery
commitment figures; and (2) the amount of funds to be repaid through
the collection of revenues through rates is now based on the single
Fiscal Year (FY) projection, instead of a projected 5-year average
calculation. These changes were required so the PUP contractors can
demonstrate payment of their portion of generation and transmission
costs, and to accommodate the yearly reconciliation of expenses under
the advance funding agreements which have been executed with the PUP
contractors and are currently being negotiated with the Firm Electric
Service (FES) contractors.
The second change concerns the ratesetting methodology. The new
rate methodology includes the PUP contractors' delivery commitments in
the calculations of the rates. This was necessary so the PUP
contractors can demonstrate payment of their portion of generation and
transmission costs.
The third change concerns the billing for firm electric service.
Due to the separation of the transmission component from the Capacity
Rate, the FES contractors will be billed a Capacity Rate of dollars per
kilowatt per month, an Energy Rate of mills per kilowatthour, and a
Firm Transmission Rate of dollars per kilowatt per month.
The fourth change concerns the updating of the expense and other
revenue estimates for FY 1997 and the cost evaluation period of FY 1998
through FY 2002 as a result of better data.
The final change concerns the significant decrease in the
transmission contract rate of delivery (CROD) used to calculate the
Firm Transmission Rate, Firm Transmission Rate of Salt Lake City Area
Integrated Projects (SLCA/IP) Power, and Nonfirm Transmission Rate. The
decrease in the CROD resulted primarily from changes in delivery
commitments.
A comparison of the existing rates and rates for FY 1998 calculated
in accordance with the proposed rate methodology are as follows:
[[Page 63151]]
Comparison of Existing Rates and Proposed Rate Methodology Rates
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Existing Rate Proposed Rate
(FY 1995) (FY 1998) \1\ Difference
----------------------------------------------------------------------------------------------------------------
Rate Schedule: PD-F5 PD-F6
Firm Capacity Rate ($/kW-month).......................... $1.92 $0.56 ($1.36)
Firm Energy Rate (mills/kWh)............................. 1.95 1.29 (0.67)
Composite Rate (mills/kWh)............................... 6.33 2.57 (3.76)
Rate Schedule: PD-FT5 & PD-
FCT5 PD-FT6 & PD-
FCT6
Firm Transmission Rate ($/kW-month)...................... $0.96 $1.08 $0.12
Firm Transmission Rate for SLCA/IP ($/kW-month).......... $0.96 $1.08 $0.12
Rate Schedule: PD-NFT5 PD-NFT6
Nonfirm Transmission Rate (mills/kWh).................... 2.19 2.47 0.28
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\1\ New rates will be calculated in accordance with the rate schedules each year by September 1. These rates
represent FY 1998 only.
The decrease in the Firm Energy Rate and Firm Capacity Rate for FY
1998 can be attributed to a large revenue carryover balance from FY
1997, the removal of the transmission component from the Firm Capacity
Rate which will be billed separately, and the inclusion of the
contracted energy and capacity for the PUP contractors. The increase in
the Firm Transmission Rate, Firm Transmission Rate of SLCA/IP Power,
and Nonfirm Transmission Rate can be attributed to a significant
decrease in the CROD used to calculate these rates even though there is
a large revenue carryover balance from FY 1997.
Statement of Annual Revenue Requirement
The Annual Revenue Requirement Allocated to Generation and
Transmission will be based upon the net amount between the estimated
expenses and other revenue as presented in the Cost Apportionment
Study. The Power Repayment Study (PRS) will document these expenses and
other revenue. The difference between the estimated and the actual
Annual Revenue Requirement Allocated to Generation and Transmission for
the rate year will be used to adjust the next year's Annual Revenue
Requirement.
By Amendment No. 3 to Delegation Order No. 0204-108, published
November 10, 1993 (58 FR 59716), the Secretary of Energy (Secretary)
delegated (1) the authority to develop long-term power and transmission
rates on a nonexclusive basis to the Administrator of Western; (2) the
authority to confirm, approve, and place such rates into effect on an
interim basis to the Deputy Secretary; and (3) the authority to
confirm, approve, and place into effect on a final basis, to remand, or
to disapprove such rates to FERC. Existing DOE procedures for public
participation in power rate adjustments (10 CFR Part 903) became
effective on September 18, 1985 (50 FR 37835).
These power and transmission rates are established pursuant to
Section 302(a) of the Department of Energy (DOE) Organization Act, 42
U.S.C. Sec. 7152(a), through which the power marketing functions of the
Secretary of the Interior and the Bureau of Reclamation (Reclamation)
under the Reclamation Act of 1902, 43 U.S.C. 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 project system involved,
were transferred to and vested in the Secretary, acting by and through
the Administrator of Western.
Rate Order No. WAPA-75, confirming, approving, and placing the
proposed rate methodology for determining rates for existing
contractors from the P-DP into effect on an interim basis, is issued,
and the new Rate Schedules PD-F6, PD-FT6, PD-FCT6, and PD-NFT6 will be
submitted promptly to FERC for confirmation and approval on a final
basis. Western is developing open access tariffs consistent with FERC
Order No. 888 and intends to publish short-term rates by November 1997,
and to submit long-term rates to the FERC by April 1, 1998.
Dated: November 18, 1997.
Elizabeth A. Moler,
Deputy Secretary.
Department of Energy Deputy Secretary
Order Confirming, Approving, and Placing the Parker-Davis Project Firm
Power Service Rate, Firm Transmission Service Rate, and Nonfirm
Transmission Service Rate Into Effect on an Interim Basis
November 1, 1997.
The rate methodology is established pursuant to Section 302(a) of
the Department of Energy (DOE) Organization Act, 42 U.S.C.
Sec. 7152(a), through which the power marketing functions of the
Secretary of the Interior and the Bureau of Reclamation (Reclamation)
under the Reclamation Act of 1902, 43 U.S.C. 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 project system involved
were transferred to and vested in the Secretary of Energy (Secretary),
acting by and through the Administrator of Western.
By Amendment No. 3 to Delegation Order No. 0204-108, published
November 10, 1993 (58 FR 59716), the Secretary delegated (1) the
authority to develop long-term power and transmission rates on a
nonexclusive basis to the Administrator of the Western Area Power
Administration (Western); (2) the authority to confirm, approve, and
place such rates into effect on an interim basis to the Deputy
Secretary; and (3) the authority to confirm, approve, and place into
effect on a final basis, to remand, or to disapprove such rates to the
Federal Energy Regulatory Commission. Existing DOE procedures for
public participation in power rate adjustments (10 CFR Part 903) became
effective on September 18, 1985 (50 FR 37835).
Acronyms and Definitions
As used in this rate order, the following acronyms and definitions
apply:
$/kW-month: Monthly charge for capacity. $/kW-season and S/kW-year
are converted to a monthly rate ($ per kilowatt per month) for billing
purposes.
$/kW-season: Seasonal rate for capacity ($ per kilowatt per
season). This is used with the Firm Transmission Rate of Salt Lake City
Area Integrated Projects power.
[[Page 63152]]
$/kW-year: Yearly rate for capacity ($ per kilowatt per year). This
is used with the Firm Transmission Rate and the Capacity Rate.
Annual Revenue Requirement: The revenue that Western needs to meet
repayment criteria, which serves as the basis for allocation between
generation and transmission.
Annual Revenue Requirement Allocated to Generation: The dollar
amount that has been allocated to Generation. This amount is used to
calculate the Energy Rate, Capacity Rate, and Composite Rate.
Annual Revenue Requirement Allocated to Transmission: The dollar
amount that has been allocated to Transmission. This amount is used to
calculate the Firm Transmission Rate, Firm Transmission Rate of Salt
Lake City Area Integrated Projects, and Nonfirm Transmission Rate.
Annual Energy: The total annual energy entitlement for the PUP and/
or FES contractors.
Capacity Rate: Expressed in $/kW-month and applied to each kW of
the FES contractor's seasonal CROD and each kW over the FES
contractor's seasonal CROD, as applicable.
Energy Rate: Expressed in mills per kilowatthour (mills/kWh) and
applied each billing period to each kWh of the FES contractor's monthly
energy entitlement, each kWh over the FES contractor's monthly energy
entitlement, and to each kWh of excess energy sold, as applicable.
CIA: Compound Interest Amortization.
Cost Apportionment Study: A study which allocates P-DP's total
costs and other revenue between generation and transmission.
CROD: Contract Rate of Delivery.
Customer Brochure: A document prepared for public distribution
explaining the background of the rate proposal contained in this rate
order.
DOE: Department of Energy.
DOE Order RA 6120.2: An order dealing with power marketing
administration financial reporting.
FERC: Federal Energy Regulatory Commission.
FES: Firm Electric Service.
FY: Fiscal Year.
Interior: U.S. Department of the Interior.
kW: Kilowatt.
kW-month: Kilowatt-month.
kW-season: Kilowatt-season.
kW-year: Kilowatt-year.
kWh: Kilowatthour.
mills/kWh: Mills per kilowatthour--the unit of charge for energy.
NEPA: National Environmental Policy Act of 1969.
O&M: Operation and Maintenance.
P-DP: Parker-Davis Project.
Proposed Rate: A rate adjustment that the Administrator of Western
recommends to the Deputy Secretary.
Provisional Rate: A rate which has been confirmed, approved, and
placed into effect on an interim basis by the Deputy Secretary.
PRS: Power Repayment Study.
PUP: Priority Use Power.
Reclamation: Bureau of Reclamation, U.S. Department of the
Interior.
Seasonal CROD: The CROD that FES contractors are entitled to during
winter season and summer season. P-DP winter season is October through
February and summer season is March through September. SLCA/IP winter
season is October through March and summer season is April through
October.
SLCA/IP: Salt Lake City Area Integrated Projects.
Western: Western Area Power Administration, U.S. Department of
Energy.
Effective Date
The new rate methodology for determining the rates for existing P-
DP contractors will become effective on an interim basis beginning
November 1, 1997, and remain in effect pending FERC's approval on a
final basis for a 59-month 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 developing the method for determining the total Annual
Revenue Requirement, Annual Revenue Requirement Allocated to
Generation, Annual Revenue Requirement Allocated to Transmission,
Energy Rate, Capacity Rate, Firm Transmission Rate, Firm Transmission
Rate of SLCA/IP Power, and Nonfirm Transmission Rate.
The following summarizes the steps Western took to ensure
involvement of interested parties in the rate process:
1. Review and discussion of the rate methodology and allocating
factors were conducted at several meetings with the contractors and
interested parties. These meetings were held October 24, 1996, November
18, 1996, January 16, 1997, April 21, 1997, and August 8, 1997.
2. Discussion of the changes to the proposed rate methodology and
resulting rates were initiated at an informal P-DP contractor meeting
held on May 7, 1997, in Phoenix, Arizona. At this informal meeting,
Western explained the need for a change in the estimates and
methodology used to calculate the charges and rates.
3. A Federal Register notice was published on May 23, 1997 (62 FR
28465), officially announcing the proposed firm power rate, firm
transmission rate, and nonfirm transmission rate adjustment, initiating
the public consultation and comment period, announcing the public
information and public comment forums, and presenting procedures for
public participation.
4. On June 3, 1997, a letter was mailed from Western to all P-DP
firm power, firm transmission, and nonfirm transmission customers and
other interested parties providing a copy of the P-DP Rate Brochure
dated May 1997 which included a copy of the Federal Register notice of
May 23, 1997.
5. At the public information forum held on June 10, 1997, Western
and Reclamation representatives explained the proposed rate
methodology, a change in the proposed billing procedures, and outlined
the changes in the Annual Revenue Requirement for Rate Year 1998 in
greater detail and answered questions.
6. The comment forum was held on July 14, 1997, to give the public
an opportunity to comment for the record. Six persons representing
customers and customer groups made oral comments.
7. On August 14, 1997, a letter was mailed from Western to all P-DP
firm power, firm transmission, and nonfirm transmission customers and
other interested parties providing a copy of the revised PRS and
related tables. The letter stated the final proposed rates and reminder
of the coming close of the comment period.
8. Six comment letters were received during the 90-day consultation
and comment period. The consultation and comment period ended August
21, 1997. All formally submitted comments have been considered in the
preparation of this rate order.
Project History
The Parker Dam Power Project was authorized by Section 2 of the
Rivers and Harbors Act of August 30, 1935 (49 Stat. 1039), 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. 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
[[Page 63153]]
facilitate water delivery for downstream irrigation requirements and
for water delivery beyond the boundary of the United States as required
by the Mexican Water Treaty. Operation of the powerplant began in
January 1951 with a generating capacity of 225,000 kW. During the
period 1974-1978 the generator nameplate capacity was increased to
240,000 kW by rewinding the generator stators.
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 the Bureau of Reclamation
(Reclamation) with funds advanced by the Metropolitan Water District of
Southern California (MWD). Lake Havasu, the reservoir created behind
Parker Dam, serves as the forebay from which water is diverted into the
MWD aqueduct. The aqueduct delivers a major portion of California's
entitlement of Colorado River water to southern California and is the
diversion point for delivering Central Arizona Project water to
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 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 Parker Powerplant at any given
time.
All facilities of the P-DP were operated and maintained by
Reclamation until the formation of the Department of Energy pursuant to
the Department of Energy Organization Act (DOE Act), 42 U.S.C. Sections
7101 et seq., enacted by Congress on August 4, 1977. Pursuant to
Section 302 of the DOE Act (42 U.S.C. 7152), responsibility for the
power marketing functions of Reclamation, including the construction,
operation, and maintenance of substations, transmission lines and
attendant facilities was transferred to the Department of Energy. The
responsibility for operation and maintenance of the dams and
powerplants remains with Reclamation.
Power Repayment Studies
A PRS is prepared each FY to determine if power revenues will be
sufficient to repay, within the prescribed time periods, all costs
assigned to the power function. Repayment criteria are based on law,
policies, and authorizing legislation. DOE Order RA 6120.2, Section
12b, requires that:
In addition to the recovery of the above costs (operation and
maintenance and interest expenses) on a year-by-year basis, the
expected revenues are at least sufficient to recover (1) each dollar of
power investment at Federal hydroelectric generating plants within 50
years after they become revenue producing, except as otherwise provided
by law; plus, (2) each annual increment of Federal transmission
investment within the average service life of such transmission
facilities or within a maximum of 50 years, whichever is less; plus,
(3) the cost of each replacement of a unit of property of a Federal
power system within its expected service life up to a maximum of 50
years; plus, (4) each dollar of assisted irrigation investment within
the period established for the irrigation water users to repay their
share of construction costs; plus, (5) other costs such as payments to
basin funds, participating projects, or States.
Existing and Provisional Rates
A comparison of the existing rates and rates for FY 1998 calculated
in accordance with the provisional rate methodology are as follows:
Comparison of Existing Rates and Proposed Rate Methodology Rates
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Provisional
Existing Rate Rate (FY 1998) Percent Change
(FY 1995) \1\ (%)
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Firm Power Service Rate Schedule: PD-F5 PD-F6
Capacity Rate ($/kW/month)............................... $1.92 $0.56 -70.83
Energy Rate (mills/kWh).................................. 1.95 1.29 -34.36
Composite Rate (mills/kWh)............................... 6.33 2.57 -59.40
Firm Transmission Service Rate Schedule: PD-FT5 PD-FT6
Firm Transmission Charge ($/kW-month).................... $0.96 $1.08 12.50
Firm Transmission Charge for SLCA/IP ($/kW-month)........ $0.96 $1.08 12.50
Nonfirm Transmission Service Rate Schedule: PD-NFT5 PD-NFT6
Nonfirm Transmission Charge (mills/kWh).................. 2.19 2.47 12.79
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\1\ New rates will be calculated in accordance with the rate schedules each year by September 1. These rates
represent FY 1998 only.
Certification of Rate
Western's Administrator has certified that the rate methodology for
determining the P-DP firm power rate, firm transmission rate,
transmission service SLCA/IP rate, and nonfirm transmission rate,
placed into effect on an interim basis herein are the lowest possible
consistent with sound business principles. The rate methodology has
been developed in accordance with administrative policies and
applicable laws.
Discussion
Western is requesting approval to place into effect a ratesetting
methodology that will be used each year to calculate the total Annual
Revenue Requirement, Annual Revenue Requirement Allocated to
Generation, Annual Revenue Requirement Allocated to Transmission,
Capacity Rate, Energy Rate, Firm Transmission Rate, Firm Transmission
Rate of SLCA/IP Power, and Nonfirm Transmission Rate. For FY 1998, the
ratesetting methodology produces a decrease in the firm power rates for
capacity and energy, and a rate increase for firm and nonfirm
transmission service for the P-DP on an interim basis. Five major
changes to the rate methodology are affecting these rates for the P-DP.
The first change concerns the Cost Apportionment Study. The study,
which demonstrates the distribution of
[[Page 63154]]
costs between generation and transmission, has been changed as follows:
(1) the PUP contractors' delivery commitments are now included in the
total amounts reflected in the generation and transmission delivery
commitment figures; and (2) the amount of funds to be repaid through
the collection of revenues through rates is now based on the single FY
projection, instead of a projected 5-year average calculation. These
changes were required so the PUP contractors can demonstrate payment of
their portion of generation and transmission costs, and to accommodate
the yearly reconciliation of expenses under the advance funding
agreements which have been executed with the PUP contractors and are
currently being negotiated with the FES contractors.
The second change concerns the ratesetting methodology. The new
rate methodology includes the PUP contractors' delivery commitments in
the calculations of the rates. This was necessary so the PUP
contractors can demonstrate payment of their portion of generation and
transmission costs.
The third change concerns the billing for FES. Due to the
separation of the transmission component from the Capacity Rate, the
FES contractors will be billed a Capacity Rate of dollars per kilowatt
per month, an Energy Rate of mills per kilowatthour, and a Firm
Transmission Rate of dollars per kilowatt per month.
The fourth change concerns the updating of the expense and other
revenue estimates for FY 1997 and the cost evaluation period of FY 1998
through FY 2002 as a result of better data.
The final change concerns the significant decrease in the
transmission CROD used to calculate the Firm Transmission Rate, Firm
Transmission Rate of Salt Lake City Area Integrated Projects Power, and
Nonfirm Transmission Rate. The decrease in the CROD resulted primarily
from changes in delivery commitments.
With these changes to the existing methodology, the proposed rate
methodology will yield annual revenues sufficient to satisfy the cost-
recovery criteria set forth in DOE Order RA 6120.2. The existing Annual
Revenue Requirement and Annual Revenue Requirement for FY 1998 for the
P-DP are as follows:
------------------------------------------------------------------------
Estimated Revenue
(Rounded to
Nearest $1,000)
-------------------
Existing FY 1998
------------------------------------------------------------------------
Annual Revenue Requirement.......................... $28,522 $25,036
Annual Revenue Requirement for Generation........... 4,495 3,459
Annual Revenue Requirement for Transmission......... 24,027 21,577
------------------------------------------------------------------------
Statement of Revenue and Related Expenses
The Annual Revenue Requirement for Generation and the Annual
Revenue Requirement for Transmission are based upon a ratebase PRS and
a Cost Apportionment Study which estimates the annual costs less other
revenues. The following table provides a summary of revenue and expense
data through the 5-year period FY 1998-FY 2002 at the provisional
rates, compared to the 5-year period FY 1996-FY 2000 at the current
rates.
Parker-Davis Project Comparison of 5-Year Rate Period Revenues and
Expenses
[$1,000]
------------------------------------------------------------------------
Current Provisional
Rate PRS Rate PRS Difference
1996-2000 1998-2002
------------------------------------------------------------------------
Total Revenues...................... $180,212 $189,728 $9,516
Revenue Distribution:
O&M............................... 114,874 123,447 8,573
Purchased Power................... 4,500 2,170 (2,330)
Other............................. 1,017 769 (248)
nterest........................... 56,452 58,342 1,890
Investment Repayment.............. 3,014 3,496 482
Capitalized Expenses Repayment.... 355 $1,504 1,149
-----------------------------------
Total........................... 180,212 189,728 9,516
------------------------------------------------------------------------
Basis for Rate Development
The rates are calculated using the Annual Revenue Requirement for
Generation and the Annual Revenue Requirement for Transmission as
calculated in the Cost Apportionment Study. As a result of this study
for FY 1998, 86.18 percent of the P-DP costs are to be recovered from
the firm transmission service, while the remaining 13.82 percent of the
costs are to be recovered from firm power and PUP service. The rate
design consists of seven steps.
1. The data in the Cost Apportionment Study is updated yearly with
the latest (1) approved budget plans for the next 5 years, (2)
principal and interest payments derived from the PRS for the next 5
years, (3) estimate of other revenue, (4) number of electric service
and transmission contractors for the next 5 years, (5) amount of energy
commitments for the next 5 years, (6) amount of CROD for the next 5
years, (7) amount of in-service investments in the plant accounts since
1987, and (8) 5-year historical capitalized movable property expense
data.
2. From the Cost Apportionment Study, the Annual Revenue
Requirement Allocated to Generation and Transmission is derived on a
yearly basis.
3. The firm transmission rate is developed by dividing the Annual
Revenue Requirement Allocated to Transmission by the average monthly
billing CROD, rounded to the penny, to determine the yearly rate. The
monthly billing rate is equal to the yearly rate divided by 12, rounded
to the penny. Transmission sales include the contracted transmission
capacity with the firm transmission service customers, FES customers,
and PUP customers.
4. The Capacity Rate, Energy Rate, and the Composite Rate are
calculated. The Capacity Rate is calculated by taking 50 percent of the
Annual Revenue Requirement Allocated to Generation divided by the sum
of the Average Monthly Billing CROD for the PUP contractors and FES
contractors, rounded to the penny, to determine the yearly rate. The
monthly billing rate is equal to the yearly rate divided by 12, rounded
to the penny.
The Energy Rate is calculated by taking 50 percent of the Annual
Revenue Requirement Allocated to Generation divided by the sum of the
Annual Energy obligation for the PUP contractors and the Annual Energy
obligation for the FES contractors, rounded to two decimal places.
The composite rate is calculated by taking the Annual Revenue
Requirement Allocated to Generation divided by the sum of the Annual
Energy obligation for the PUP contractors and the Annual Energy
obligation for the FES contractors, rounded to two decimal places.
5. The firm transmission rate for delivery of SLCA/IP power is
determined by dividing the firm transmission service rate in half,
rounded to the penny to determine the seasonal rate. The monthly
billing rate
[[Page 63155]]
is equal to the seasonal rate divided by six, rounded to the penny.
6. The nonfirm transmission rate is calculated by taking the firm
transmission rate yearly rate divided by the product of 8,760
multiplied by 60 percent with the result multiplied by 1,000, rounded
to two decimal places.
7. The FES contractors are billed monthly an energy charge, a
capacity charge, and a transmission charge. The contractor's monthly
energy charge is equal to the contractor's monthly energy entitlement
multiplied by the energy rate. The contractor's monthly capacity charge
is equal to the contractor's seasonal billing CROD multiplied by the
monthly capacity rate. The contractor's monthly transmission charge is
equal to the contractor's seasonal billing CROD multiplied by the
monthly firm transmission rate.
Comments
During the 90-day comment period, Western received six written
comments either requesting information or commenting on the rate
adjustment. In addition, six persons commented during the July 14,
1997, public comment forum. All comments were reviewed and considered
in the preparation of this rate order.
Written comments were received from the following sources:
R. W. Beck, Arizona Public Service Company, Overton Power District No.
5 and Valley Electric Association, Irrigation & Electrical Districts
Association of Arizona, K. R. Saline & Associates, and Citizens
Utilities Company.
Representatives of the following organizations made oral comments:
Arizona Power Authority, Citizens Utilities Company and Arizona Public
Service Company, Salt River Project, Irrigation & Electrical District
Association of Arizona and the City of Needles, CA, Overton Power
District No. 5, Valley Electric Association, and the Town of Fredonia,
AZ, and K. R. Saline & Associates.
The comments received at the public meetings and in correspondence
dealt with (1) the development of better allocators for apportioning
the costs and other revenues between generation and transmission; (2)
the finalization of budget estimates and what costs should go into
those estimates; (3) the changes in contract relationships with
contractors and their effect on the rates; and (4) the use of the PRS.
The comments and responses, paraphrased for brevity, are discussed
below. Direct quotes from comment letters are used for clarification
where necessary.
Issue: A contractor commented that the ``customer allocator'' used
in the Cost Apportionment Study does not sufficiently provide for a
direct relationship between cost-causation and the recovery of expenses
through rates. The customer requests serious consideration of this
issue be addressed in the future.
Response: Western has given this issue serious consideration during
this rate process and will continue to examine this issue during the
next rate process. Additional information concerning the allocation
factors is discussed below.
Issue: A customer commented that a reexamination of the cost
allocation factors would not be cost beneficial and would result in
only a minor change to the overall allocation percentages.
Response: At this time, Western cannot predict what the effect to
the overall allocation percentages would be upon reexamination of the
cost allocation factors. With the overall revenue requirement for the
P-DP approaching $30 million, even a minor change to the overall
allocation percentages may significantly affect some of Western's
smaller customers.
Issue: A comment was made that the public comment period be
continued for an additional 30 to 60 days in order to further review
the cost allocation factors and to analyze the allocation of Western's
operation expenses.
Response: At a meeting held with contractors and interested parties
on January 16, 1997, it was agreed the cost allocation factors, as they
currently exist, remain functional and that a better process does not
exist. However, it was also agreed the allocation factors may be
revisited during future rate processes. At another meeting with the
contractors and interested parties held on August 8, 1997, it was once
again agreed the current rate process move forward using the allocation
factors that were documented and approved during the last rate process
and reaffirmed during this current rate process. Once again it was
agreed the cost allocation methods be reexamined during the next rate
process.
Issue: A customer commented that Western review its current
policies or develop new processes to mitigate the rate impacts to
remaining customers when it enters new relationships with existing
customers.
Response: Western will continue to seek to improve on existing
procedures or develop new processes that will meet Western's legislated
mandates in a fair and equitable manner. Furthermore, Western will
continue to pursue sound business practices that produce the lowest
possible rate to the extent possible.
Issue: A customer stated that staffing levels, below authorized
levels, allowed a large portion of the projected current year carryover
and suggested that Western perform a thorough review of its staffing
requirements and provide supporting evidence to its customers of any
increased staffing over current levels.
Response: Western is nearing completion of a transformation process
that began in 1995 and is expected to be complete by June of 1998. The
recommended staffing level was a result of a detailed and in-depth
analysis that evaluated all of Western's processes and recommended the
most effective and efficient staffing levels to meet Western's needs.
Any variation from those levels would require another in-depth
analysis. Western will continue to evaluate all processes for
continuous improvement and will make adjustments to staffing levels as
necessary to meet changing requirements.
Issue: A customer commented a review of the cost allocation of the
Conservation and Renewable Energy Program costs be conducted and that
these costs are not transmission related and should be allocated to
generation.
Response: It is intended the allocation of the Conservation and
Renewable Energy Program be reviewed during the next rate process.
Issue: A customer suggested that Western review the methodology
used to allocate multiproject costs and general Western administration
costs. Furthermore, another customer commented that FTE data should be
based on actual staff levels, not authorized positions, and where
possible, the use of direct allocations to responsible projects.
Response: The methodology for allocating multiproject costs was
published in a report developed in cooperation with the DSW customers.
A meeting was held with DSW customers in March 1997 to review the
methodology for allocating multiproject costs. During that meeting,
minor adjustments to the methodology were recommended and are in the
process of being implemented. Western will continue to review the
methodology to seek improvements. Any changes to the methodology will
be done in a joint customer forum.
The method for distributing general Western administration costs is
a Western-wide methodology that was implemented after a review of
Western's operations by the firm of Deloitte and Touche. Any change to
this
[[Page 63156]]
methodology would require involvement of all offices throughout
Western, and involvement of Western's auditors.
Issue: A customer commented on a recent disclosure by Western that
certain pension costs may be included in future rate processes and is
of the opinion that these costs not be included for repayment unless
legislatively mandated.
Response: Western will record the costs for pension and health
benefits in the 1997 financial statements. However, the inclusion of
these costs in the PRS will depend upon the outcome of a final decision
on Western's legal authority to include these costs in the rate base.
Issue: A customer commented about waiting for several years for
Reclamation's commitment to develop a 10-year planning process for
Parker-Davis.
Response: Reclamation has begun to develop and implement its 10-
year planning process for the Parker-Davis Project and intends for it
to be a useful and beneficial process for obtaining customer comments
and feedback.
Issue: A customer commented on the need to review the program
function of the PRS and on the possibility of developing a more
efficient tool for implementing the PRS function.
Response: Western remains open to implementing more efficient and
effective processes in the best interests of the customers. Continual
improvement of the PRS program is a goal and customer feedback is
always welcome. In the forthcoming fiscal year, Western will once again
look for ways to implement changes to the PRS program that provides for
more efficient output.
Issue: A customer commented on the potential for large rate swings
from year to year now that the rates for the Parker-Davis Project are
being calculated on an annual basis and no longer on a 5-year average.
Response: The calculation of the rate on an annual basis performs
two very critical functions. It allows for a synchronization of the
costs shown in the Cost Apportionment Study with those in the PRS and
it enables Western to perform an annual cost reconciliation to the Cost
Apportionment Study without causing a divergence to the data in the
PRS. In order to mitigate potential surprises to the customers in the
5-year out period, Western will continue to project the rates for those
years thereby allowing contractors to adequately budget for those
future costs or to mitigate those costs by providing feedback through
Western and Reclamation's 10-year planning process.
Environmental Evaluation
In compliance with the National Environmental Policy Act of 1969,
42 U.S.C. 4321 et seq.; Council on Environmental Quality Regulations
(40 CFR Parts 1500-1508); and DOE NEPA Regulations (10 CFR Part 1021),
Western has determined this action is categorically excluded from the
preparation of an environmental assessment or an environmental impact
statement.
Executive Order 12866
DOE has determined 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 this rate adjustment, including PRSs,
comments, letters, memorandums, and other supporting material made or
kept by Western for the purpose of developing the power rates, is
available for public review in the Desert Southwest Regional Office,
Western Area Power Administration, Office of the Assistant Regional
Manager for Power Marketing, 615 South 43rd Avenue, Phoenix, Arizona
85009; and Office of the Assistant Administrator for Power Marketing
Liaison, Room 8G-027, 1000 Independence Avenue SW., Washington, DC
20585.
Submission to Federal Energy Regulatory Commission
The rate herein confirmed, approved, and placed into effect on an
interim basis, together with supporting documents, will be submitted to
FERC for confirmation and approval on a final basis. Western is
developing open access tariffs consistent with FERC Order No. 888 and
intends to publish short-term rates by November 1997, and submit long-
term rates to the FERC by April 1, 1998.
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 November 1, 1997, Rate Schedules PD-F6, PD-FT6, PD-
FCT6, and PD-NFT6 for the Parker-Davis Project. The rate schedule shall
remain in effect on an interim basis, pending Federal Energy Regulatory
Commission confirmation and approval of it or a substitute rate on a
final basis, through September 30, 2002.
Dated: November 18, 1997.
Elizabeth A. Moler,
Deputy Secretary.
[Rate Schedule PD-F6; (Supersedes Schedule PD-F5)]
Schedule of Rates for Wholesale Firm Power Service
Effective: The first day of the first full billing period beginning
on or after November 1, 1997, and remaining in effect through September
30, 2002, or until superseded, whichever occurs first.
Available: In the marketing area serviced by the Parker-Davis
Project (P-DP).
Applicable: To the existing wholesale power customers for firm
power service supplied through one meter at one point of delivery,
unless otherwise provided by contract.
Character and Conditions of Service: Alternating current at 60
hertz, three-phase, delivered and metered at the voltages and points
established by contract.
Monthly Charge: Energy Charge. Each Contractor shall be billed
monthly an energy charge. This charge is equal to the Contractor's
monthly energy entitlement multiplied by the Energy Rate (rounded to
the penny). The Energy Rate shall be equal to 50 percent of the Annual
Revenue Requirement Allocated to Generation divided by the sum of the
Annual Energy entitlement to the P-DP Priority Use Power Contractors
and the Annual Energy entitlement to the P-DP Firm Electric Service
Contractors, rounded to two decimal places.
Capacity Charge: Each Contractor shall be billed monthly a capacity
charge. This charge is equal to the Contractor's Seasonal Billing
Contract Rate of Delivery (CROD) multiplied by the Capacity Rate,
rounded to the penny. The Capacity Rate shall be equal to 50 percent of
the Annual Revenue Requirement Allocated to Generation divided by the
sum of the Average Monthly Billing CROD for the P-DP Priority Use Power
Contractors and P-DP Firm Electric Service Contractors that is then
divided by 12, rounded to the penny.
Transmission Charge. Each Contractor shall be billed monthly a
transmission charge equal to the Contractor's Seasonal Billing Contract
Rate of Delivery (CROD) multiplied by the rate calculated in accordance
with PD-FT6, rounded to the penny.
Billing of Excess Energy: For each billing period in which there is
excess energy available, offered, and delivered to the Contractor, such
excess energy purchases shall be billed at the Energy Rate.
[[Page 63157]]
Billing for Unauthorized Overruns: For each billing period in which
there is a contract violation involving an unauthorized overrun of the
CROD, energy, and/or transmission obligations, such overruns shall be
billed at 10 times (1) the Energy Rate for energy overruns, (2) the
Capacity Rate for CROD overruns, and (3) the P-DP Firm Transmission
Rate, then in effect as it may be amended, for transmission overruns.
For Transformer Losses: If delivery is made at transmission voltage
but metered on the low-voltage side of the substation, the meter
readings will be increased to compensate for transformer losses as
provided for in the contract.
For Power Factor: The customer will normally be required to
maintain a power factor at all points of measurement between 95-percent
lagging and 95-percent leading.
[Rate Schedule PD-FT6; (Supersedes Schedule PD-FT5)]
Schedule of Rate for Firm Transmission Service
Effective: The first day of the first full billing period beginning
November 1, 1997, and remaining in effect through September 30, 2002,
or until superseded, whichever occurs first.
Available: Within the marketing area served by the Parker-Davis
Project (P-DP).
Applicable: To existing firm transmission service customers where
capacity and energy are supplied to the P-DP system at points of
interconnection with other systems and transmitted and delivered, less
losses, to points of delivery on the P-DP system specified in the
service contract.
Character and Conditions of Service: Alternating current at 60
hertz, three-phase, delivered and metered at the voltages and points
established by contract.
Monthly Rate: Transmission Service Charge: Each Contractor shall be
billed a dollar per kilowatt per year rate for each kilowatt at the
point of delivery, established by contract, payable monthly at a dollar
per kilowatt per month rate. The yearly rate is equal to the Annual
Revenue Requirement Allocated to Transmission divided by the Average
Monthly Billing Contract Rate of Delivery, rounded to the penny. The
monthly billing rate is equal to the dollar per kilowatt per year rate
divided by 12, rounded to the penny.
Adjustments: For Reactive Power. There shall be no entitlement to
transfer of reactive kilovoltamperes at delivery points, except when
such transfers may be mutually agreed upon by contractor and
contracting officer or their authorized representatives.
For Losses. Capacity and energy losses incurred in connection with
the transmission and delivery of power and energy under this rate
schedule shall be supplied by the customer in accordance with the
service contract.
Billing for Unauthorized Overruns. For each billing period in which
there is a contract violation involving an unauthorized overrun of the
contractual firm transmission obligations, such overrun shall be billed
at 10 times the above rates.
[Rate Schedule PD-FCT6; (Supersedes Schedule PD-FCT5)]
Schedule of Rate for Firm Transmission Service of Salt Lake City
Area Integrated Projects Power
Effective: The first day of the first full billing period beginning
on or after November 1, 1997, and remaining in effect through September
30, 2002, or until superseded, whichever occurs first.
Available: Within the marketing area served by the Parker-Davis
Project (P-DP) transmission facilities.
Applicable: To existing Salt Lake City Area Integrated Projects
(SLCA/IP) southern division customers where SLCA/IP capacity and energy
are supplied to the P-DP system by the Colorado River Storage Project
(CRSP) at points of interconnection with the CRSP system and for
transmission and delivery on a unidirectional basis, less losses, to
southern division customers at points of delivery on the P-DP system
specified in the service contract.
Character and Conditions of Service: Alternating current at 60
hertz, three-phase, delivered and metered at the voltages and points of
delivery established by contract.
Monthly Rate: Transmission Service Charge: Each Contractor shall be
billed a dollar per kilowatt per seasonal rate for each kilowatt at the
point of delivery, established by contract, payable monthly at a dollar
per kilowatt per month rate. The seasonal rate is equal to the P-DP
Firm Transmission Rate then in effect as it may be amended divided by
2, rounded to the penny. The monthly billing rate is equal to the
dollar per kilowatt per season rate divided by six, rounded to the
penny.
Adjustments: For Reactive Power. There shall be no entitlement to
transfer of reactive kilovoltamperes at delivery points, except when
such transfers may be mutually agreed upon by contractor and
contracting officer or their authorized representatives.
For Losses. Capacity and energy losses incurred in connection with
the transmission and delivery of power and energy under this rate
schedule shall be supplied by the customer in accordance with the
service contract.
Billing for Unauthorized Overruns. For each billing period in which
there is a contract violation involving an unauthorized overrun of the
contractual firm transmission obligations, such overrun shall be billed
at 10 times the above rates.
[Rate Schedule PD-NFT6; (Supersedes Schedule PD-NFT5)]
Schedule of Rate for Nonfirm Transmission Service
Effective: The first day of the first full billing period beginning
on or after November 1, 1997, and remaining in effect through September
30, 2002, or until superseded, whichever occurs first.
Available: Within the marketing area serviced by the Parker-Davis
Project (P-DP) transmission facilities.
Applicable: To existing nonfirm transmission service customers
where capacity and energy are supplied to the P-DP system at points of
interconnection with other systems, transmitted subject to the
availability of the transmission capacity, and delivered on a
unidirectional basis, less losses, to points of delivery on the P-DP
system specified in the service contract.
Character and Conditions of Service: Alternating current at 60
hertz, three-phase, delivered and metered at the voltages and points of
delivery established by contract.
Monthly Rate: Nonfirm Transmission Service Charge: Each Contractor
shall be billed monthly a mills per kilowatthour rate of scheduled or
delivered kilowatthours at point of delivery, established by contract,
payable monthly. This rate is equal to P-DP Firm Transmission dollar
per kilowatt-year rate then in effect as it may be amended divided by
(8,760 multiplied by 0.60) multiplied by 1,000, rounded to two decimal
places.
Adjustments: For Reactive Power. There shall be no entitlement to
transfer of reactive kilovoltamperes at delivery points, except when
such transfers may be mutually agreed upon by contractor and
contracting officer or their authorized representatives.
For Losses. Capacity and energy losses incurred in connection with
the transmission and delivery of power and energy under this rate
schedule shall be supplied by the customer in accordance with the
service contract.
[FR Doc. 97-31074 Filed 11-25-97; 8:45 am]
BILLING CODE 6450-01-P