[Federal Register Volume 63, Number 65 (Monday, April 6, 1998)]
[Notices]
[Pages 16778-16796]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-8938]
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DEPARTMENT OF ENERGY
Western Area Power Administration
Loveland Area Projects--Rate Order No. WAPA-80
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-80
and Rate Schedules L-NT1, L-FPT1, N-FPT1, L-AS1, L-AS2, L-AS3, L-AS4,
L-AS5, and L-AS6, placing formula rates into effect on an interim basis
for firm and non-firm transmission on the Western Area Power
Administration Loveland Area Projects (LAP) transmission system and for
ancillary services for the Western Area Colorado Missouri control area
(WACM). These schedules supersede Rate Schedules LT-3 and LT-4.
The charges for network and point-to-point transmission service and
energy imbalance service will be implemented in three steps, between
April 1, 1998, and October 1, 1999. The charges for the other five
ancillary services will be implemented in the first step. Each step and
subsequent annual recalculation will be based on updated financial data
and loads. Network transmission service charges will be based on the
Transmission Customer's load-ratio share of the annual revenue
requirement for transmission. Point-to-point transmission service will
be based on monthly reserved capacity on the transmission system. The
charges for ancillary services will be based on the costs of the WACM.
FOR FURTHER INFORMATION CONTACT: Mr. Daniel T. Payton, Rates Manager,
Rocky Mountain Customer Service Region, Western Area Power
Administration, P.O. Box 3700, Loveland, CO 80539-3003, (970) 490-7442,
or e-mail (dpayton@wapa.gov).
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 non-exclusive 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 the Federal Energy Regulatory
Commission (FERC).
Rate Order No. WAPA-80, confirming, approving, and placing the LAP
network, firm point-to-point, and non-firm point-to-point transmission,
and the new ancillary services formula rates into effect on an interim
basis, is issued. Rate Order No. WAPA-80 was prepared pursuant to
Delegation Order No. 0204-108, existing DOE procedures for public
participation in power rate adjustments in 10 CFR Part 903, and
procedures for approving Power Marketing Administration rates by FERC
in 18 CFR 300. The new Rate Schedules L-NT1, L-FPT1, L-NFPT1, L-AS1, L-
AS2, L-AS3, L-AS4, L-AS5, and L-AS6 will be promptly submitted to FERC
for confirmation and approval on a final basis.
Dated: March 23, 1998.
Elizabeth A. Moler,
Deputy Secretary.
In the Matter of: Western Area Power Administration, Rate
Adjustment for Loveland Area Projects Transmission and Ancillary
Services
April 1, 1998.
Order Confirming, Approving, and Placing the Loveland Area Projects
Transmission and Ancillary Service Formula Rates Into Effect on an
Interim Basis
These transmission and ancillary service formula rates are
established pursuant to Section 302 of the Department of Energy (DOE)
Organization Act, 42 U.S.C. 7152(a), through which the power marketing
functions of the Secretary of the Interior and the Bureau of
Reclamation (Reclamation) were transferred to and vested in the
Secretary of Energy (Secretary).
By Amendment No. 3 to Delegation Order No. 0204-108, published
November 10, 1993 (58 FR 59716), the Secretary delegated: (1) the
authority to develop long-term power and transmission rates on a non-
exclusive 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 are found in 10 CFR Part 903. Procedures for approving
Power Marketing Administration rates by FERC are found in 18 CFR Part
300.
Acronyms/Terms and Definitions
As used in this rate order, the following acronyms/terms and
definitions apply:
Acronym/Term Definition
$/kW-month: Monthly charge for capacity (i.e., $ per kilowatt (kW)
per month).
12 cp: Rolling 12-month coincident peak average.
A&GE: Administrative and general expense.
C&RE: Conservation and Renewable Energy.
CME: Capitalized movable equipment.
CRSP: Colorado River Storage Project.
Customer Brochure: ``Loveland Area Projects Customer Brochure:
Proposed Rates for Transmission and Ancillary Services'' prepared in
September 1997 by the Rocky Mountain Customer
[[Page 16779]]
Service Region for public distribution explaining the background and
purpose of this rate adjustment proposal.
DOE: U.S. Department of Energy.
DOE Order RA 6120.2: An order addressing power marketing
administration financial reporting, used in determining revenue
requirements for rate development.
Federal Customers: Loveland Area Projects (LAP) customers taking
delivery of long-term firm service under Firm Electric Service
Contracts, and Project Use Power Customers.
FERC: Federal Energy Regulatory Commission.
FERC Order No. 888: FERC Order Nos. 888, 888-A, 888-B, and 888-C
unless otherwise noted.
Firm Electric Service Contract: Contracts for the sale of long-term
firm LAP Federal energy and capacity, pursuant to the Post-1989 General
Power Marketing and Allocation Criteria (Marketing Plan).
FY: Fiscal Year.
kW: Kilowatt; 1,000 watts.
kWh: Kilowatt-hour; the common unit of electric energy, equal to
one kW taken for a period of 1 hour.
kW-month: Unit of electric capacity, equal to the maximum of kW
taken during 1 month.
LAP: Loveland Area Projects.
LAP Transmission System Total Load: Average 12-cp monthly system
peak for network transmission service, average 12-cp monthly
entitlements of Federal Customers, and reserved capacity for all firm
point-to-point transmission service.
Load ratio share: Network Transmission Customer's hourly load
(including its designated network load not physically interconnected
with Western) coincident with Western's monthly transmission system
peak.
Long-term firm point-to-point transmission service: Annual firm
point-to-point transmission service reservation with 12 consecutive
equal monthly amounts.
mill: Unit of monetary value equal to .001 of a U.S. dollar; i.e.,
1/10th of a cent.
mills/kWh: Mills per kilowatt-hour.
Monthly entitlements: Maximum capacity to be delivered each month
under Firm Electric Service Contracts. Each monthly entitlement is a
percentage of the seasonal contract-rate-of-delivery, based on 90-
percent hydrologic probability established in the Marketing Plan.
MW: Megawatt; equal to 1,000 kW or 1,000,000 watts.
NEPA: National Environmental Policy Act of 1969.
NPPD: Nebraska Public Power District.
O&M: Operation and maintenance.
P-SMBP: Pick-Sloan Missouri Basin Program.
P-SMBP-WD: Pick-Sloan Missouri Basin Program-Western Division.
PMOC: Power Marketing and Operations Complex.
Post-1989 General Power Marketing and Allocation Criteria: Criteria
for the sale of energy with capacity from the P-SMBP-WD and the
Fryingpan-Arkansas Project by Criteria: the RMR.
Provisional Rate Schedule: Rate schedule approved on an interim
basis by the Deputy Secretary of the DOE.
Reclamation: Bureau of Reclamation, U.S. Department of the
Interior.
RMR: The Rocky Mountain Customer Service Region; Western's office
in Loveland, Colorado.
Service agreement: The initial agreement and any amendments or
supplements thereto entered into by the Transmission Customer and
Western for service under the Tariff.
SEPA: Southeastern Power Administration.
Short-term firm point-to-point transmission service: Firm point-to-
point transmission service with service of less duration than 12
consecutive monthly service amounts.
Supporting documentation: Work papers which support the rate
proposal.
Tariff: Western Area Power Administration, Open Access Transmission
Service Tariff, Docket No. NJ-98-1-000.
Transmission Customer: The RMR customer taking network or point-to-
point transmission service.
WACM: Western Area Colorado Missouri control area.
Western: Western Area Power Administration, U.S. Department of
Energy.
Effective Date
The provisional formula rates will become effective on an interim
basis on the first day of the first full billing period beginning on or
after April 1, 1998, and will be in effect pending FERC's approval of
them or substitute formula rates on a final basis through March 31,
2003, or until superseded. These formula rates will be applied under
existing transmission contracts and Western's Open Access Transmission
Service Tariff (Tariff) and conform with the spirit and intent of the
FERC Order No. 888. The Rocky Mountain Customer Service Region (RMR)
will replace Schedules 1 through 8 and Attachment H of Western's Tariff
with these rate schedules for service on the Loveland Area Projects
(LAP) system.
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 these formula rates and schedules. The
provisional firm transmission rate represents an increase of more than
1 percent in total LAP transmission revenues; therefore, it is a major
rate adjustment as defined at 10 CFR 903.2(e) and 903.2(f)(1).
The distinction between a minor and a major rate adjustment is used
only to determine the public procedures for the rate adjustment.
The following summarizes the steps Western took to ensure
involvement of interested parties in the rate process:
1. During the spring of 1997, RMR representatives met informally
with individual LAP customers to explain the need for a rate
adjustment.
2. RMR published a Federal Register notice on September 19, 1997
(62 FR 49218), officially announcing the proposed transmission and
ancillary services rates adjustment, initiating the public consultation
and comment period, announcing the public information and public
comment forums, and outlining procedures for public participation.
3. On September 25, 1997, RMR mailed a copy of the ``Loveland Area
Projects Customer Brochure: Proposed Rates for Transmission and
Ancillary Services'' to all LAP Transmission Customers and other
interested parties.
4. RMR held a public information forum on October 23, 1997, in
Denver, Colorado. Western representatives explained the need for the
rate adjustment in greater detail and answered questions.
5. RMR held a comment forum on November 18, 1997, in Denver,
Colorado, to provide the public an opportunity to comment for the
record. Four individuals commented at this forum.
6. Seven commentors submitted letters during the 90-day
consultation and comment period. The consultation and comment period
ended on December 18, 1997. All comments have been considered in the
preparation of this Rate Order.
Comments
Representatives of the following organizations made oral comments:
Platte River Power Authority, Colorado, on behalf of Loveland Area
Customer Association
Colorado Springs Utilities (CSU), Colorado
[[Page 16780]]
Kansas Electric Power Cooperative, Inc., Kansas
New Century Energies, Texas, on behalf of Public Service Company of
Colorado, Colorado, and Cheyenne Light, Fuel and Power Company, Wyoming
The following organizations submitted written comments:
Arkansas River Power Authority, Colorado
Colorado Springs Utilities, Colorado
Loveland Area Customer Association, Colorado
Nebraska Public Power District (NPPD), Nebraska
Platte River Power Authority, Colorado
New Century Energies, Texas
Tri-State Generation and Transmission Association, Inc. (Tri-State),
Colorado
Project Description
RMR offers transmission service on LAP transmission facilities,
which include transmission lines, substations, communication equipment,
and related facilities. LAP is comprised of two power projects: the
Pick-Sloan Missouri Basin Program-Western Division (P-SMBP-WD) and the
Fryingpan-Arkansas Project (Fryingpan-Arkansas). The two projects were
integrated for operational and marketing purposes in 1989. LAP serves
Federal and Transmission Customers in a four-state area, over a
transmission system of approximately 3,485 miles (5,607 circuit
kilometers) and 80 substations.
Western will offer ancillary services from the Western Area
Colorado Missouri control area (WACM) resources, which represent a
combination of some Colorado River Storage Project (CRSP) generation
resources and all of the LAP generation resources.
P-SMBP-WD
The initial stages of the Missouri River Basin Project were
authorized by Section 9 of the Flood Control Act of 1944 (58 Stat. 887,
891, Pub. L. 534, 78th Congress, 2nd session). It was later renamed the
Pick-Sloan Missouri Basin Program (P-SMBP). The P-SMBP encompasses a
comprehensive program, with the following authorized functions: flood
control, navigation improvement, irrigation, municipal and industrial
water development, and hydroelectric production for the entire Missouri
River Basin. Multipurpose projects have been developed on the Missouri
River and its tributaries in Colorado, Montana, Nebraska, North Dakota,
South Dakota, and Wyoming.
The Colorado-Big Thompson, Kendrick, Riverton, and Shoshone
Projects were administratively combined with P-SMBP in 1954, followed
by the North Platte Project in 1959. These projects are known as the
``Integrated Projects'' of the P-SMBP. The Riverton Project was
reauthorized as a unit of the P-SMBP in 1970.
The P-SMBP-WD and the Integrated Projects include 19 powerplants.
There are six powerplants in the P-SMBP-WD: Glendo, Kortes, and Fremont
Canyon Powerplants on the North Platte River; Boysen and Pilot Butte on
the Wind River; and Yellowtail Powerplant on the Big Horn River.
In the Colorado-Big Thompson there are also six powerplants. The
Green Mountain Powerplant on the Blue River is on the West Slope of the
Rocky Mountains. The five remaining powerplants are on the East Slope
of the Continental Divide: Marys Lake, Estes, Pole Hill, Flatiron, and
Big Thompson.
The Kendrick Project has two power production facilities: Alcova
and Seminoe Powerplants. Power production facilities in the Shoshone
Project are Shoshone, Buffalo Bill, Heart Mountain, and Spirit Mountain
Powerplants. The only production facility in the North Platte Project
is the Guernsey Powerplant.
Fryingpan-Arkansas Project
The Fryingpan-Arkansas is a transmountain diversion project in
central and southeastern Colorado, which was authorized by the Act of
August 16, 1962 (Pub. L. 87-590, 76 Stat. 389, as amended by Title XI
of the Act of October 27, 1974, Pub. L. 93-493, 88 Stat. 1487, 1497).
The Fryingpan-Arkansas diverts water from the Fryingpan River and other
tributaries of the Roaring Fork River to the Arkansas River on the East
Slope of the Continental Divide. The Fryingpan and Roaring Fork Rivers
are part of the Colorado River Basin on the West Slope of the Rocky
Mountains. The water diverted from the West Slope, together with
regulated Arkansas River water, provides supplemental irrigation,
municipal and industrial water supplies, and hydroelectric power
production. Flood control, fish and wildlife enhancement, and
recreation are other important purposes of the Fryingpan-Arkansas. The
only generating facility in the Fryingpan-Arkansas Project is the Mt.
Elbert Pumped-Storage Powerplant on the East Slope of the Rocky
Mountains.
Colorado-River Storage Project
The CRSP was authorized by the Colorado River Storage Project Act,
ch. 203, 70 Stat. 105, on April 11, 1956. The CRSP provides for the
comprehensive development of the Upper Colorado River Basin (Upper
Basin). It furnishes the long-term regulatory storage needed to allow
states in the Upper Basin (Colorado, New Mexico, Utah, and Wyoming) to
meet their water delivery obligations to the states of the Lower Basin
(Arizona, California, and Nevada) and still use the water apportioned
to them by the Colorado River Compact of 1922. The part of the CRSP in
WACM is the territory north of Shiprock, New Mexico. The CRSP
hydroelectric facilities providing ancillary services for WACM are
Aspinall (formerly Curecanti) and part of Glen Canyon. As of April 1,
1998, the southern portion of the CRSP will be operated by Western's
Desert Southwest Customer Service Region in Phoenix, Arizona.
LAP Transmission Service
RMR prepared a transmission service rate study based on cost of
service for the LAP transmission system. RMR is seeking approval of
formula rates for calculation of point-to-point transmission rates and
the network transmission service revenue requirement. These formulas
will be applied annually. Transmission service for delivery of LAP
long-term firm Federal power to Federal Customers will continue to be
bundled in their firm power rate under existing contracts which expire
in 2024. The transmission rates include the cost of Scheduling, System
Control, and Dispatch Service.
The existing LAP transmission rate of $1.88/kW-month, placed into
effect under Rate Schedule L-T3 in 1994, is no longer sufficient to
recover annual costs (including interest expense) and capital
requirements. Although the cost basis for the transmission rates has
changed since 1994, the primary reason for a rate adjustment is the
reassessment of the load data. A detailed review of load and meter data
has determined that the loads used in the 1994 analysis (1,957,882 kW)
were significantly in excess of actual system use (1,126,263 kW) and
were not billable under the terms of LAP contracts.
About 500 MW of the difference is over-projections of actual usage
of the transmission service. Approximately 200 MW is due to the use of
a non-coincident annual peak in the 1994 rate analysis, as opposed to
the use of the FERC-endorsed 12-consecutive peak (12-cp) method in the
provisional rates. About 100 MW for an existing contract that is billed
at a discounted rate was excluded from the present rate denominator and
included as a revenue credit. In combination, these factors result in
approximately 800 MW of reduced load on the LAP transmission
[[Page 16781]]
system, with a corresponding increase in transmission rates.
RMR will offer existing Transmission Customers the opportunity to
convert their existing contracts to service agreements under Western's
Tariff. The customer will designate network or point-to-point
transmission service and applicable ancillary services. The earliest
that an existing transmission contract can be converted under the
Tariff and the Provisional Rate Schedules is April 1, 1998.
For the formula rates, RMR assumed that all existing contracts that
are based on capacity or energy transmitted will take network
transmission service, and that customers which currently reserve
capacity for transmission service will take point-to-point transmission
service. If an existing Transmission Customer elects to retain its
transmission contract, transmission service will continue under the
terms of the existing contract, but under the Provisional Rate
Schedules (L-NT1, L-FPT1, and L-NFPT1 for transmission, and L-AS1, L-
AS2, L-AS3, L-AS4, L-AS5, and L-AS6 for ancillary services). These
Provisional Rate Schedules will supersede the rate schedules in the
existing contracts. If an existing Transmission Customer is billed on
an energy (rather than capacity) basis, the Provisional Rate Schedules
stipulate that the rate per capacity unit will be converted to a rate
per energy unit, based on the individual Transmission Customer's load
factor.
RMR recognizes the impact that the increase in cost for
transmission service from $1.88/kW-month to $3.19/kW-month may have on
its customers. RMR is proposing a three-step implementation plan for
the transmission rate adjustment in an attempt to mitigate these
impacts. The implementation dates and basis for the calculation for
each of the three steps are described below. The starting point for the
calculation is an estimate of the third-step rate, based on Fiscal Year
(FY) 1996 financial data and 1995 load data. In subsequent steps, the
third-step rate will be recalculated based on the formula rate and
updated financial and load data.
Step 1--April 1, 1998
The first-step point-to-point rate is the existing rate ($1.88/kW-
month) plus one-third of the difference between the existing rate and
the estimated third-step rate. The network transmission service revenue
requirement is the first-step point-to-point rate multiplied by the LAP
Transmission System Total Load.
Step 2--October 1, 1998
The second-step point-to-point rate will be the existing rate
($1.88/kW-month) plus two-thirds of the difference between the existing
rate and the recalculated third-step rate. The third-step rate will be
recalculated, following the formula rate, using FY 1997 financial and
load data.
Step 3--October 1, 1999
The third-step point-to-point transmission service rate and network
transmission service revenue requirement will be recalculated,
following the formula rates and FY 1998 financial and load data.
The rates will subsequently be recalculated every year, effective
October 1, based on the approved formula rates and updated financial
and load data. RMR will provide customer notice of changes in rates no
later than July 1 of each year.
Ancillary Services
RMR will offer the six ancillary services defined by FERC to all
customers. The six ancillary services are: (1) Scheduling, System
Control, and Dispatch Service; (2) Reactive Supply and Voltage Control
from Generation Sources Service (VAR Support); (3) Regulation and
Frequency Response Service (Regulation); (4) Energy Imbalance Service;
(5) Spinning Reserves; and (6) Supplemental Reserves. The ancillary
services formula rates are designed to recover only the costs incurred
for providing the service(s). The rates for ancillary services are
based on WACM control area costs, per FERC.
RMR will implement the Energy Imbalance Service bandwidths
simultaneously with the transmission service rates to allow for a
transition period, whereby, customers may improve their equipment and
revise their scheduling practices. The implementation schedule will be:
April 1, 1998--6 percent bandwidth
October 1, 1998--5 percent bandwidth
October 1, 1999--3 percent bandwidth
Comparison of Existing and Provisional Rates for Transmission and
Ancillary Services
The following is a comparison of existing rates, step-one rates,
and an estimate of the step-three rates under the provisional formula
rates and using FY 1996 data. Rates for step-two and three will be
recalculated based on updated financial and load data prior to
implementation. Subsequently, these rates will be updated annually
based on approved formula rates.
Comparison of Existing, Step-One, and Estimated Step-Three Rates
----------------------------------------------------------------------------------------------------------------
Rate schedule and
Class of service Existing rate schedule Rate schedule and step- estimated step-three
and rate one rates April 1, 1998 rates \1\
----------------------------------------------------------------------------------------------------------------
Firm Transmission.................... LT-3................... L-NT1 or L-FPT1, and L- L-NT1 or L-FPT1, and L-
AS1 thr. 6. AS1 thr. 6.
$1.88/kW-mo............ See applicable classes See applicable classes
below. \2\. below.\2\
Network Transmission................. N/A.................... L-NT1.................. L-NT1
Load ratio share of \1/ Load ratio share of \1/
12\ of the revenue 12\ of the revenue
requirement of requirement of
$31,555.162 \3\. $43,153,308 \3\
Firm Point-to-Point Transmission..... N/A.................... L-FPT1................. L-FPT1
$2.32/kW-mo \3\........ $3.19/kW-mo \3\
Non-firm Point-to-Point Transmission. LT-4................... L-NFPT1................ L-NFPT1
2.6 mills/kWh.......... Maximum of 3.33 mills/ To be calculated
kWh. October 1, 1999.
Scheduling, System Control, and N/A.................... L-AS1.................. L-AS1
Dispatch. $25.71 per schedule per To be calculated
day for non- October 1, 1999.
transmission customers.
Reactive Supply and Voltage Control N/A.................... L-AS2.................. L-AS2
from Generation Sources. $0.112/kW-mo........... To be calculated
October 1, 1999.
Regulation and Frequency Response.... N/A.................... L-AS3.................. L-AS3
$0.147/kW-mo........... To be calculated
October 1, 1999.
Energy Imbalance..................... N/A.................... L-AS4.................. L-AS4
[[Page 16782]]
For negative excursions For negative excursions
outside of 6% outside of 3%
bandwidth (2 MW bandwidth (2 MW
minimum) and occurring minimum) and occurring
more than 5 times per more than 5 times per
month, RMR reserves month, RMR reserves
the right to charge the right to charge
100 mills/kWh. 100 mills/kWh.
Positive excursions Positive excursions
outside the bandwidth outside the bandwidth
may be credited to the may be credited to the
customer within 30 customer within 30
days for 50 % of the days for 50 % of the
regional average regional average
monthly price for non- monthly price for non-
firm purchases.\4\. firm purchases.\4\
Spinning/Supplemental Reserves....... N/A.................... L-AS5 and 6............ L-AS5 and 6
Long-term Reserves are Long-term Reserves are
not available from not available from
WACM. WACM.
Reserves will be Reserves will be
provided on a pass- provided on a pass-
through cost. through cost.
----------------------------------------------------------------------------------------------------------------
\1\ To be recalculated October 1, 1999.
\2\ Rate Schedule stipulates that if an existing Transmission Customer is billed on an energy basis, the rate
per capacity unit will be converted to a rate per energy unit, based on individual customer's load factor.
\3\ If a Transmission Customer requires use of LAP subtransmission facilities for delivery of non-Federal
energy, a specific facility use charge will be assessed.
\4\ During times when over deliveries would impinge on WACM operations, RMR reserves the right to eliminate
credits.
Certification of Rates
Western's Acting Administrator has certified that the LAP
transmission and ancillary services rates placed into effect on an
interim basis herein are the lowest possible consistent with sound
business principles. The formula rates have been developed in
accordance with agency administrative policies and applicable laws.
LAP Transmission Service Discussion
The charges for network and point-to-point transmission service
will be implemented in three steps between April 1, 1998, and October
1, 1999. Each step will be recalculated based on the updated financial
data and loads. Network service charges will be based on the
Transmission Customer's load-ratio share of the annual revenue
requirement for transmission. Point-to-point service will be based on
reserved capacity on the transmission system.
Annual Transmission Revenue Requirement: The Annual Transmission
Revenue Requirement will be applicable to both network and point-to-
point transmission service.
The Annual Transmission Revenue Requirement is the Annual
Transmission Cost, adjusted for revenue credits and costs associated
with expenses which expand the capacity available for transmission. The
formula is:
[GRAPHIC] [TIFF OMITTED] TN06AP98.003
Following is an estimate of the third-step revenue requirement,
using FY 1996 data. This revenue requirement will be recalculated every
October.
$43,153,308 = $44,669,889 + $0-$837,908-$678,671
The Transmission Expenses Which Increase Transmission System
Capacity will include any future credits paid to Transmission Customers
from augmentation of the system. The credits will be addressed in the
individual service agreements, and appropriate adjustments will be made
in subsequent rate calculations. Western will evaluate these requests
in accordance with guidance in FERC Order No. 888-A, Section IV.G.1.g:
``* * * for a customer to be eligible for a credit, its facilities must
not only be integrated with the transmission provider's system, but
must also provide additional benefits to the transmission grid in terms
of capability and reliability, and be relied upon for the coordinated
operation of the grid.''
Miscellaneous Revenue Credits may include, but will not be limited
to non-firm, discounted firm, and short-term firm transmission sales;
Scheduling, System Control, and Dispatch Service; or facility charges
for transmission facility investments included in the revenue
requirement. The non-firm point-to-point transmission service credit is
estimated to be $788,064, based on the non-firm transmission sales made
on the LAP transmission system during the time period of July 1996 to
June 1997. Credits for scheduling service are estimated to be $19,540.
Credits for facility charges are $30,304.
The Revenue Credit For Existing Transmission Contracts includes the
transmission revenue received from PacifiCorp under Contract No. 14-06-
400-2437. The loads served under this contract were excluded from the
total system load. This contract is a 1-mill reciprocal agreement that
requires a 3-year notification for cancellation. Western gave the
required 3-year notice to PacifiCorp in May 1997. This revenue credit
shall be included in the revenue requirement calculation until such
time as the contract terminates. At that time, the loads will be added
to the LAP Transmission System Total Load for rate determination.
[[Page 16783]]
The Annual Transmission Cost is the product of the Annual Fixed
Charge Rate and the Net Investment Cost for Transmission Facilities.
The formula is:
Annual Transmission Cost = Annual Fixed Charge Rate x Net Investment
Cost for Transmission Facilities
This formula applied to FY 1996 data is:
$44,669,889 = 19.194%* x $232,731,025
*Actual percentage carried out to five decimal places.
The Net Investment Cost for Transmission Facilities was determined
by an analysis of the LAP transmission system. Each LAP facility was
identified by function: transmission, subtransmission, distribution, or
generation-related. Only the investment costs of the facilities
identified as ``transmission'' were used in developing the proposed
transmission rates. The investment costs of facilities identified as
``subtransmission'' and ``distribution'' were allocated to LAP Federal
Customers. The LAP subtransmission system is used primarily for
delivery of Federal power to Federal Customers. If a Transmission
Customer requires the use of the subtransmission system, an additional
facility-use charge will be assessed. All costs of Fryingpan-Arkansas
were considered generation-related; and therefore, included with other
generated-related cost in the revenue requirement for ancillary
services.
The facilities identified as performing the function of
transmission include all transmission lines that are normally operated
in a continuously-looped manner and the associated substations and
switchyard facilities. In the LAP transmission system, these are
primarily the 115-kV and 230-kV transmission lines. In addition, a
portion of the communication and maintenance facilities was included in
the investment costs for transmission. The total investment cost for
transmission facilities, as of September 30, 1996, is $304,913,006. The
allowance for depreciation on these facilities is $72,181,981, yielding
a net investment cost of $232,731,025.
The Annual Fixed Charge Rate includes operation and maintenance
(O&M) expenses, administrative and general expenses (A&GE),
depreciation expenses, and interest expenses. The formula is:
[GRAPHIC] [TIFF OMITTED] TN06AP98.004
This formula applied to FY 1996 data is:
19.194% = 6.003% + 1.647% + 3.084% + 8.460%
The source for the annual O&M, A&GE, depreciation, and interest
expenses is the Results of Operations for the Rocky Mountain Customer
Service Region--Pick-Sloan Missouri Basin. The source for the unpaid
balance is the amount reported in the Historical Financial Document in
Support of the Power Repayment Study for the Pick-Sloan Missouri Basin
Program.
Transmission System Load: The LAP Transmission System Total Load is
the average 12-cp monthly system peak for network transmission service,
the 12-cp monthly entitlements for Federal Customers, and the reserved
capacity for all firm point-to-point transmission service.
The LAP Transmission System Total Load is calculated as follows,
based upon 1995 data and known and measurable charges:
[GRAPHIC] [TIFF OMITTED] TN06AP98.005
This load was derived as follows:
Obtained hourly individual revenue meter readings for
delivery points on the LAP transmission system. This included all
delivery points in the Firm Electric Service Contracts for Federal
power, auxiliary power from a non-Federal source, project use and
special customers, and third-party wheeling delivery points.
Subtracted the meter readings for point-to-point
Transmission Customers to determine the network transmission service
load.
Added the reserved capacity for point-to-point
Transmission Customers to determine the LAP Transmission System Total
Load.
Network Transmission Service: The monthly charge for network
transmission service is the product of the Transmission Customer's
load-ratio share times one-twelfth of the Annual Transmission Revenue
Requirement. The customer's load-ratio share is the ratio of its
network transmission load to the LAP Transmission System Total Load,
which will be calculated on a rolling 12-cp basis.
The customer's network load will be derived as follows:
Identify the LAP transmission system peak hour for each
month.
Calculate the total delivery to each individual Network
Transmission Customer for the 12 monthly peak hours.
Identify the part of the total delivery associated with
each customer's monthly LAP monthly entitlement.
Identify the network delivery during each of the 12
monthly peaks (total delivery minus monthly entitlement for delivery of
Federal power).
Sum the 12 monthly peaks and divide by 12 months to derive
the 12 cp for each Network Transmission Customer.
Firm Point-to-Point Transmission Service: The proposed rate for
firm point-to-point transmission service is the Annual Transmission
Revenue Requirement, divided by the LAP Transmission System Total Load.
Firm
[[Page 16784]]
point-to-point transmission service is available for a period of 1 day
or longer.
The formula for the proposed rate is as follows:
[GRAPHIC] [TIFF OMITTED] TN06AP98.006
Following is an estimate of the third-step rate, using FY 1996
data. This rate will be recalculated every October.
[GRAPHIC] [TIFF OMITTED] TN06AP98.007
Non-Firm Point-to-Point Transmission Service: Non-firm transmission
service is available for periods ranging from 1 hour to 1 month. The
rate for non-firm transmission service may be discounted based on
market conditions, but will never be higher than the firm point-to-
point transmission rate, converted to an energy equivalent at 100
percent load factor. The formula for the non-firm transmission service
rate is:
[GRAPHIC] [TIFF OMITTED] TN06AP98.008
Based on the Firm Point-to-Point Transmission Rate, an estimate of
the maximum Non-Firm Point-to-Point Transmission Rate for the third
step is:
Monthly delivery: $3.19/kW of reserved capacity per month
Weekly delivery: $0.74/kW of reserved capacity per week
Daily delivery: $0.11/kW of reserved capacity per day
Hourly delivery: 4.58 mills/kWh
Transmission Service Comments
The following comments were received during the public comment
period. RMR paraphrased and combined comments when it did not affect
the meaning. RMR's response follows each comment. Changes were made in
the formula rates and calculations as a result of the comments noted.
Comment: In order to avoid any confusion, Western may wish to
clarify that when using the term ``existing contracts'' it is referring
solely to transmission contracts and is not suggesting that the
unbundling provision of FERC Order No. 888 is applicable to the
statutory obligations of Western.
Response: RMR agrees and has made this change in the Rate Order to
avoid confusion.
Comment: One commentor is concerned that RMR has designed a single
transmission service rate to apply to existing agreements which have
drastically varying billing parameters. Historically, this practice of
billing non-standard agreements under a single rate schedule has
resulted in each Transmission Customer effectively paying a different
charge per kW of annual transmission capacity reserved, with the
customers being billed on annual reserved capacity paying the highest
charge. On pages 10-11 of the Customer Brochure, RMR proposes to
continue this inequitable treatment by billing these existing
agreements and any new service provided under Western's Tariff under
the same proposed rate schedule. In order to avoid under-recovery of
revenue requirements, RMR has essentially allocated cost responsibility
to each of its existing transmission arrangements on the basis of the
disparate billing parameters specified in these agreements and ignored
the annual transmission capacity reserved under these arrangements.
This approach is inequitable and inconsistent with the intent of FERC
Order No. 888 and causes Transmission Customers billed on annual
reserved capacity to subsidize other customers on the LAP system. One
of the fundamental principles established in FERC Order No. 888 is that
all Transmission Customers should pay, on a comparable basis, for the
full amount of the transmission capacity they reserve and/or use.
Response: RMR agrees with the commentor that the existing LAP
transmission rate applied to the existing transmission agreements has
resulted in Transmission Customers effectively paying different charges
per kW of annual transmission capacity reserved and/or used. RMR also
recognizes that because the existing LAP transmission rate was based on
a projected denominator, the existing LAP rate results in Federal
Customers paying about $6.9 million annually more than their comparable
share of the LAP transmission costs due to unbillable projections.
RMR will correct this disparity in charging. RMR developed the
formula rates under the assumption that all existing Transmission
Customers will switch to service agreements under Western's Tariff.
These service agreements will eliminate the disparity that currently
exists.
RMR has also taken steps to eliminate the disparity even if some
Transmission Customers elect to retain their existing contracts. With
the exception of Contract No. 14-60-400-2437 with PacifiCorp, LAP
transmission rate adjustments are implemented by changing the rate
schedules which are attached to the contracts. As stated on pages 10-11
of the Customer Brochure, if an existing customer elects to retain its
existing transmission contract, transmission service will continue
under the conditions of the existing contract, but under the
Provisional Rate Schedules. The Provisional Rate Schedules stipulate
that if an existing Transmission Customer is billed on an energy
(rather than capacity) basis, the rate per capacity unit will be
converted to a rate per energy unit, based on the
[[Page 16785]]
individual Transmission Customer's load factor. This stipulation and
the use of 12 cp for both network and point-to-point transmission
service will result in all customers (billed on capacity usage, energy
usage, or reserved capacity) paying the same rate per capacity unit.
To avoid over/under recovery, RMR has developed the rate
denominator (load) based on the same amount as the projected billing
determinant, assuming all customers switch to service agreements. If
necessary, the rate denominator will be adjusted for Step Two of the
rate adjustment to reflect the appropriate load for any Transmission
Customer that does not switch to a service agreement; e.g., if a
customer elects to retain its existing contract and is, therefore,
billed on non-coincidental peak capacity, or on an energy basis, the
appropriate billing determinant will be substituted in the rate
denominator. Therefore, Step One will also serve as a transition period
to align all customers on a comparable basis, with no risk of over
collecting.
During Step One and Step Two of the transition period, Transmission
Customers will actually be paying less than their full share of
transmission, with the Federal Customers making up the difference. By
the end of the Step Three, equitability between Federal Customers and
Transmission Customers will be achieved.
Comment: Several commentors support RMR's intent to continue to
provide bundled transmission service in the firm electric service rate.
One commentor states, ``The Flood Control Construction Act of 1944,
which authorized the Missouri River Basin Project, required that the
rate schedules be calculated with `regard to the recovery * * * of the
costs of producing and transmitting' the electric energy generated by
the hydro powerplants authorized. This is a statutory prescription of
bundled service.''
Response: LAP firm power rates were last adjusted in 1994,
following the public process as described in 10 CFR 903. These rates
were developed, consistent with the Post-1989 General Power Marketing
Plan and Allocation Criteria (Marketing Plan), which established the
capacity and energy available to market under Firm Electric Service
Contracts. The Firm Electric Service Contracts expire in 2024.
Transmission will remain bundled in RMR's firm power rate and
contracts. RMR's intent to continue to provide this service as a
bundled product is consistent with FERC Order No. 888, Section
IV.G.2.(a) which does not require that transmission service for bundled
native load be taken under the FERC Pro Forma.
Comment: RMR has improperly designated existing transmission
arrangements as network transmission service. RMR assumes that the
existing bundled transmission service, included with firm preference
power sales, and the existing firm transmission service, provided to
certain Preference Power Customers for delivery of auxiliary power
supplies in addition to RMR's scheduled sale, qualifies for rate
treatment as network transmission service loads. Such rate treatment is
improper because:
(1) These existing, partial requirements transmission arrangements
do not meet the FERC's definition of, or requirements for, network
loads, as discussed in FERC Order No. 888-A and the FERC Pro Forma, and
(2) Such treatment ignores the existing contractual arrangements
that reserve a specific, and in most cases, a limited amount of
transmission capacity for these deliveries.
The commentor states that the full requirements transmission
deliveries associated with LAP project and special use sales are the
only existing transmission service deliveries on LAP transmission
system which currently qualify as network loads. LAP preference power
sales are prescheduled deliveries with contractual limits that, by
design, are intended to serve only a portion of the customer's load
requirements.
The commentor quotes the definition of network load in the FERC Pro
Forma, Section 1.22, and quotes Section IV.G.1.c.(3) and (4) of FERC
Order No. 888-A in support of its position. To avoid duplicating the
transmission charges, the commentor recommends RMR follow the
guidelines in Section IV.G.1.c.(4).
Response: RMR has properly designated existing transmission
arrangements as network transmission service. The definition of network
load in the FERC Pro Forma, Section 1.22, states, ``A Network Customer
may elect to designate less than its total load as network load but may
not designate only part of the load at a discrete point of delivery.''
The Marketing Plan and the existing Firm Electric Service Contracts
(implementing Western's statutory obligations to market Federal power)
establish RMR's contractual rights for delivery of Federal long-term
firm capacity and energy to electric service and project-use customers.
RMR is the Transmission Customer for delivery of all long-term firm
electric service.
RMR, as a Transmission Customer, has designated its entire load at
the points of delivery in the Firm Electric Service Contracts as
network-type service. The remaining load at each discrete point of
delivery is served under a separate transmission service agreement. It
is anticipated that each Transmission Customer will take service for
its entire load at each discrete point of delivery in a Network
Integration Service Agreement. The entire load at each discrete point
will be served by network-type service.
RMR is following an alternative offered in FERC Order No. 888-A,
Section IV.G.1.c.(4), to avoid double payments for transmission
service. This Section states, ``The Network Customer then has two
options: pursue negotiations with the transmission provider to obtain a
credit on its network service bill for any separate transmission
arrangements . . . in recognition of the network transmission now being
provided and paid for under the tariff.''
Federal Customers will continue to pay a bundled firm power rate
under their Firm Electric Service Contract. A Network Transmission
Customer's network service bill will include a credit for the load
designated by RMR as Firm Electric Service, and the customer will only
pay network transmission service for the remainder of its loads,
thereby, eliminating any duplicate charge.
Without this arrangement, LAP Transmission Customers would be
precluded from receiving network transmission service, which would not
allow them the comparable use of the system that RMR and others enjoy.
FERC approved a similar crediting arrangement in a ruling on a Duke
Power Company (Duke) Case, Docket No. ER 97-2398-000, 81 FERC 61010. In
this case, FERC ruled that a portion of the customers' load could be
met by the Southeastern Power Administration (SEPA) allocation (which
is a network transmission service) and a portion could be served under
Duke's bundled service, which is of a network nature. The entire load
would be served on a network basis. Payment would be made to Duke by
SEPA for the SEPA Preference Customers' allocation and by the
Preference Customers for the remainder of their loads. Without such
arrangements, all Preference Customers of Federal power marketing
administrations would be precluded from receiving network transmission
service for their auxiliary supply.
Comment: In support of the above comment, the commentor states that
most of the existing auxiliary
[[Page 16786]]
transmission agreements include provisions that require RMR to make a
4-year commitment to reserve a specific amount of transmission
capacity.
Response: The commentor has misinterpreted RMR's auxiliary
transmission contracts. RMR's existing network-type Transmission
Customers pay only for the transmission service used, not for a firm
reservation, as implied by the commentor. RMR's existing network-type
transmission contracts include estimates of the amount of transmission
capacity required by the customer for service over and above the
capacity provided under the Firm Electric Service Contracts. This
estimate is similar to the 10-year forecast required in the Application
for Network Integration Service, which is updated annually by the
Network Transmission Customer for use in transmission planning. Also,
RMR retains the right to resell any capacity not used by the Network
Transmission Customer.
Comment: RMR's proposed capacity obligation is drastically
understated. The commentor gives eight reasons for this statement. Each
reason is addressed separately below:
Reason 1: It was the commentor's understanding that the LAP
hydrogeneration resources are required, by statute, to generate at
their full capacity and make every effort to avoid letting water from
the reservoir bypass the generators during high water/heavy runoff
conditions. RMR is then obligated to sell this excess generation
output. If this understanding is accurate, then RMR should include the
full output capacity of these resources as a firm reservation on the
LAP transmission system, as it did in the March 1993 transmission rate
study to insure that transmission capacity is available to accommodate
such required generation.
Response: The commentor's understanding is inaccurate. RMR is not
required to generate at full capacity. The full operating capacity of
the hydrogenerators is not a valid indicator of RMR's use of the LAP
transmission system. The maximum transmission capacity available to RMR
for delivery of firm electric service is the total capacity under
contract in the Firm Electric Service Contracts.
If high hydro conditions do occur, and the water cannot be stored
in the reservoirs, RMR offers available seasonal energy first to
existing Federal Customers to increase the load factor associated with
their contract rate of delivery, per Section V.D.2.b. of the Marketing
Plan. Any surpluses not marketed to Federal Customers will be marketed
by a Western merchant function and will require point-to-point
transmission under Western's Tariff. These non-firm sales on the
transmission system are reflected as a revenue credit to the firm
transmission revenue requirement; thereby, reducing the obligation of
the other users of the system.
RMR did not use the full output capacity of its hydro resources in
its 1993 transmission rate study. RMR used the P-SMBP-WD operating
plant capacity at the 90-percent hydrologic probability of exceedance
of 761,500 kW, which was established in the Marketing Plan. The 761,500
kW includes reserves and required maintenance which are not included in
the marketable capacity.
The rate denominator should only include the amounts that are
marketed and hence can be billed. Therefore, RMR included only the
monthly capacities marketed under the Firm Electric Service Contracts
in the rate denominator for the formula rates. These marketed
capacities are the monthly capacity entitlements. It is assumed that
these capacity entitlements are always used for peak monthly deliveries
of firm Federal power.
Reason 2: RMR does not recognize a separate transmission obligation
for the Town of Julesburg, Colorado, which established its own
arrangements for firm, auxiliary transmission service with RMR under
Contract No. 96-RMR-914, dated November 15, 1996.
Response: RMR agrees and has corrected the denominator to account
for network transmission service to the Town of Julesburg of 1,272 kW
(12 cp).
Reason 3: RMR did not recognize the October 2, 1997, revision to
Exhibit B of Contract No. 88-LAO-376 with Public Service Company of
Colorado (PSCo).
Response: This Exhibit B revision was made after the publication of
the Customer Brochure in September 1997. RMR has subsequently changed
the denominator (from 180,320 to 195,638 kW) to account for the FY 1998
reserved capacity for PSCo.
Reason 4: Several of the auxiliary transmission service agreements
provide for the transmission of pumped-storage return energy, but it is
not clear whether such off-peak, point-to-point transmission service is
provided on a firm or non-firm basis. To the extent that such service
is non-firm and the sum of the customer's firm and non-firm service
deliveries never exceed the customer's firm capacity reservation, it is
appropriate for RMR to provide such non-firm service without an
additional charge or reservation.
Response: This network-type service is for serving network load,
specifically the return of pumped-storage energy, from network
resources. The transmission of pumped-storage return energy is always
off-peak and, hence, does not add to the customer's usage on the system
monthly peak.
Reason 5: RMR and PacifiCorp have a reciprocal obligation, under
Contract No. 14-06-400-2437, to provide firm transmission service for
each other at a discounted rate of 1 mill per kWh delivered. The
agreement provides for a 3-year notice to terminate these arrangements,
but Western did not provide such notice to PacifiCorp until May 1997.
Instead of including this PacifiCorp transmission reservation (152,750
kW) in the LAP capacity obligation calculation, RMR proposes to include
the test period discounted transmission revenue from this agreement as
a credit to the LAP transmission revenue requirement. Under this
reciprocal arrangement, Western and PacifiCorp provide discounted firm
transmission service for each other that exclusively benefits the
generation/power merchant functions within these organizations. Long-
term, firm Transmission Customers of the LAP system are not offered
similar discounted rates. Western has received less than full
transmission compensation from PacifiCorp in exchange for wheeling
arrangements on the PacifiCorp system which benefits Western's
generation marketing efforts.
Response: This is an existing contract, which the Federal
Government arranged in good faith over 20 years ago at a regionally
standard rate of 1 mill/kWh. This contract did not include a provision
for adjusting the rate schedule. Over the years, PacifiCorp's use of
the RMR system has increased, and RMR's use of PacifiCorp's system has
remained relatively constant.
The commentor has contended that RMR has benefited from the
reciprocal arrangement. However, the loss of revenue to RMR has far
outweighed the benefit to RMR under this contract. This contract does
not exclusively benefit RMR's generation/merchant function. In 1998,
PacifiCorp will provide only 12,500 kW of transmission capacity for
RMR, and RMR will provide 164,500 kW of transmission capacity for
PacifiCorp. RMR receives a benefit of about $230,000 per year (if RMR
were to pay PacifiCorp's wheeling rate of $24.30/kW/year in place of
the 1 mill/kWh). RMR is annually foregoing over $3.0 million, assuming
PacifiCorp takes network transmission service. Therefore, RMR included
a revenue credit in the rate design, to reflect
[[Page 16787]]
transmission payment from PacifiCorp at a rate less than the embedded
costs and excluded the loads from the denominator.
Consistent with RMR's effort to align all Transmission Customers on
a comparable basis, Western has given PacifiCorp the required advance
notice that this contract will be terminated in May 2000. PacifiCorp
will then be required to pay the transmission rate based on embedded
costs, and the loads will be added to the denominator.
Reason 6: RMR included the summer and winter monthly reservations
for NPPD under Contract No. 87-LAO-200. RMR's proposed rate treatment
of this transmission obligation has the effect of discriminating
against Transmission Customers that purchase long-term, firm point-to-
point transmission service on the basis of an annual capacity
reservation and whose load patterns could be exactly like that of NPPD.
Response: It appears the commentor assumed that the NPPD contract
is a long-term point-to-point contract. RMR recognizes that long-term
point-to-point service is for 12 equal monthly reservations; however,
NPPD has an existing contract for a seasonal reservation, and RMR must
honor it for the remainder of its term. Future service agreements for
unequal monthly reservations (like the service provided to NPPD) will
be considered short-term point-to-point. Revenue from future short-term
point-to-point service agreements will be treated as a revenue credit,
and the load will be excluded from the denominator; thereby, not
affecting long-term Transmission Customers.
It is anticipated that NPPD will retain its existing transmission
contract; therefore, the monthly reservations for which it will pay the
point-to-point rate were included in the rate denominator. Thereby, the
rate design is consistent with the billing amounts in the contract and
no over/under recovery will occur.
Reason 7: RMR has understated the total capacity reservation for
Municipal Energy Agency of Nebraska (MEAN). Under Contract No. 89-LAO-
487, Exhibit A, RMR has a firm obligation to transmit up to 1,934 kW of
power and energy. Likewise, under Exhibit B, RMR is separately
obligated to transmit up to 22,156 kW. It is not clear why RMR's
calculation includes only the obligation in Exhibit B, but it appears
that RMR has understated the total capacity reservation.
Response: MEAN has indicated that they will elect to take network
transmission service. The 12 cp for MEAN has been added under network
load in the rate denominator. The issue raised by the commentor,
therefore, is no longer applicable.
Reason 8: RMR has a firm obligation to transmit up to 103,000 kW of
power and energy for the Rocky Mountain Generation Cooperative, Inc.
(RMGC). RMR's calculation shows a slightly different amount.
Response: RMGC has a firm transmission capacity reservation for
100,000 kW, to Sidney, Nebraska, which RMR included as point-to-point
service. RMGC also received firm transmission service to the Town of
Basin, Wyoming, and paid for the maximum service received, which is
estimated by RMGC as 3,000 kW. RMR included this 12-cp load of 2,583 kW
as network transmission service.
As of January 1998, transmission service from the Town of Basin was
deleted from the RMGC contract and added to the Tri-State transmission
agreement. RMR has made this adjustment in the rate denominator.
Comment: One commentor supports RMR's approach to pricing firm
point-to-point service, which cannot be discounted, and pricing non-
firm service on a maximum basis, which can then be discounted.
Response: Although RMR does not anticipate offering discounted firm
point-to-point service over the LAP transmission system, Western's
Tariff does allow for discounting of firm and non-firm point-to-point
service, consistent with the FERC Pro Forma.
Comment: One commentor suggests that credits for augmentation
facilities be included in the individual Network Integration Service
Agreement for the specific customer and not be a part of the initial
rate making process. Subsequent annual revisions of the transmission
service rates should take augmentation credits into account in the
calculation of the new rate. On the same topic, another commentor
suggested that RMR work with a group of customers to define
augmentation and establish criteria for determining when and where
augmentation exists on the LAP transmission system. The resulting
definitions and objective criteria can then be applied to instances in
which augmentation is claimed. This process should occur in a manner
which allows input from all affected Federal Customers. A third
commentor opposes RMR granting augmentation credits unless it can be
demonstrated that non-Federal transmission facilities were necessary to
deliver the firm electric service to Preference Customers.
Response: In accordance with FERC Order No. 888, credits for
customer-owned facilities are best resolved on a fact-specific, case-
by-case basis. We agree that credits will be addressed in the
individual Network Integration Service Agreement, and appropriate
adjustments may be made in subsequent rate calculations. If customers
feel that augmentation credits are warranted, they should submit a
written request with sufficient data to support their claim. RMR will
evaluate such requests, with input from all affected parties, in
accordance with guidance in FERC Order No. 888-A, Section IV.G.1.g: ``*
* * for a customer to be eligible for a credit, its facilities must not
only be integrated with the transmission provider's system, but must
also provide additional benefits to the transmission grid in terms of
capability and reliability, and be relied upon for the coordinated
operation of the grid.''
Comment: In RMR's cost of capital determinations, it applies the
composite interest rate on outstanding debt to the entire net plant
investment, rather than just to the unpaid component of the net
investment. By doing so, it creates an ongoing financing cost for the
principal component of the net investment that has already been paid
back to the U.S. Treasury. Since there is no cost associated with the
repaid principal component and since these governmental entities have
no equity owners that have invested capital, such treatment is improper
and overstates the true cost of capital.
Response: Although the revenue requirement includes interest
charges on the entire amount of undepreciated plant, no ongoing finance
charge is being created through its calculation. The methodology merely
ensures that transmission users pay finance charges related to the
plant they use. These finance charges are reduced over time by the
amount of plant investment removed to accumulated depreciation or
retirements. As these investments reduce in value, so do the financing
charges associated with them.
By applying an interest component to plant that has already been
paid but not yet depreciated, RMR is recognizing prepayments made by
Federal Customers and revenues from surplus generation sales that have
been applied against outstanding transmission debt. Western's repayment
of these investments is governed by DOE Order RA 6120.2, which
prescribes repayment of revenues to the highest interest-bearing
project investments first, regardless of whether they are related to
transmission or generation. This makes it possible for principal to be
significantly reduced on transmission debt without payment by
transmission users. If the interest component is not applied to net
plant, the Transmission
[[Page 16788]]
Customers would not pay their share of the interest expense.
Western revenues repay projects whose resources are entirely hydro;
therefore, average water is used to forecast repayment revenues. This
means that some years will have high-energy sales that can be used to
prepay debt in anticipation of drought conditions, such as those from
1988 through 1993, when revenues were insufficient to meet LAP's
repayment obligations. These prepayments act as stabilizing factors
during the ebb and flow of hydrologic cycles to ensure repayment of
project obligations. RMR's transmission rates have never included
charges for interest deficits, O&M deficits, or purchase power arising
from poor water years. RMR believed that these expenses were related to
insufficient energy to meet its obligations, and the associated costs
were incorporated in the firm power rate. It would be inappropriate for
Transmission Customers to share the benefit of good water, but none of
the costs of poor water.
Comment: Revenues derived from third-party transmission service
transactions should be accounted for in future repayment.
Response: In accordance with the DOE Order RA 6120.2, all
transmission revenues are credited to the P-SMBP power repayment study,
including an estimate of future revenues to reflect this transmission
rate adjustment.
Comment: A commentor has taken issue with the way that RMR has
functionally allocated the LAP microwave communications system and the
Power Marketing and Operations Complex (PMOC). By functionally
allocating the investment of these two facilities on the basis of LAP
plant investment, which includes almost no generation-related plant,
RMR understates the amount of service provided to the generation/power
merchant function by assigning a disproportionately large amount of the
annual cost of these items to transmission. The commentor recommends
including the net plant investment costs of Reclamation in calculating
the functional allocation of RMR's costs.
Response: Although Western and Reclamation are both agencies of the
Federal Government, they function as distinct and separate entities,
both financially and functionally. On December 21, 1977, under Section
302 of the Department of Energy Organization Act, Congress established
Western, whose primary responsibility is power marketing and
transmission of the Federal generation resource. These transferred
responsibilities were previously held by Reclamation, who continues to
own, operate, and maintain the generation resources for the Federal
Government.
With regard to the commentor's issue concerning the microwave
communications allocation, Reclamation owns, operates, and maintains
its own Supervisory Communications and Data Acquisition (SCADA) system
for microwave communications, none of which is included in the
transmission rate. The cost of Reclamation's SCADA facilities are in
the RMR's calculations for the generation based ancillary services.
RMR's SCADA and microwave communications system is designed, operated,
and maintained by RMR personnel primarily for transmission system use.
Therefore, RMR asserts that its allocation of SCADA and microwave
communications costs on the basis of LAP investment is proper.
With regard to the PMOC, RMR revisited its computation for
functionally allocating the PMOC costs. RMR's methodology for this
review was an analysis of PMOC office space, and specifically, what
percentage of the office space is occupied by personnel that support
the generation function. RMR found that based on space occupied in the
PMOC by generation-dedicated employees, the amount of the PMOC to be
functionally allocated to generation should be 2.928 percent, rather
than the 3.669 percent derived from investment costs. Reallocation of
the PMOC to accommodate this .741 percentage difference increases the
amount allocated to transmission by $176,080. This is insignificant
when contrasted against the total transmission allocation of
$304,913,006. Given the relatively insignificant amounts and immaterial
rate impacts, RMR maintains that its original allocation of the PMOC
building costs based on LAP plant investment is reasonable.
Comment: One commentor also feels that RMR should use cost-tracking
allocators to functionally assign expenses, rather than allocating on
the basis of the LAP net investment. Specific FERC accounts should be
functionally allocated on the basis of what function they benefit. A&GE
expenses associated with field-type offices that provide multi-function
services should be functionally allocated using a basis that fully
recognizes the generation/power merchant function performed at these
offices. The commentor points out that certain O&M expense items,
specifically the Conservation and Renewable Energy (C&RE) Expense and
the Power Marketing and Generation Power Resources Planning Expense,
should be entirely excluded from the transmission revenue requirement
and assigned specifically to the generation/power merchant function at
RMR.
Response: As previously stated, Western's primary responsibility is
the power marketing and transmission of the Federal generation
resource. RMR provides only incidental generation support. Reclamation
owns, operates, and maintains the generation resource for the Federal
Government. Reclamation costs have not been included in the
transmission revenue requirements.
Western undertook a line item analysis of the O&M costs. Western
agrees with the commentor that the cost of C&RE could be completely
assigned to the generation function. Adjustments could be made to the
line items for Power Users Account and Collection Expenses and Power
Marketing and Generation Power Resources Planning Expenses, which would
increase the 3.669 percent allocated to generation. However, these
three adjustments amount to a decrease in the O&M allocated to
transmission by $317,455, which would reduce the fixed charges for
transmission by less than 0.1 percent. Given the relatively
insignificant amounts and immaterial rate impacts, RMR will continue to
functionally allocate the LAP O&M and A&GE costs based upon plant
investment costs. RMR reiterates that Western staff do not perform
significant generation activity.
During RMR's review of the O&M costs, an extensive reexamination of
those costs was undertaken and a determination was made that the Mt.
Elbert Powerplant O&M was classified inappropriately in the original
calculations. The original calculations assumed that Mt. Elbert was
only used for the provision of firm power; in fact, Mt. Elbert is
actually used to provide a material amount of Regulation and Frequency
Response Service and Reserves support. Therefore, RMR's costs for the
O&M of Mt. Elbert, which were originally allocated to LAP Federal
Customers, are now being included in the Annual Fixed Charge Rate for
Generation. This adjustment increases the generation O&M costs by $3
million, the addition of which yielded no impact to the ancillary
service rates.
Comment: RMR included in the transmission revenue requirement the
charges it pays to NPPD for transmission service under Contract No. 87-
LAO-200. The transmission service from NPPD provides no long-term, firm
transmission capacity to RMR beyond
[[Page 16789]]
that which is required and reserved to serve RMR's firm generation
service loads located in southern Nebraska and northern Kansas and
which are captive to the NPPD transmission system. Consequently, the
long-term firm Transmission Customer on the LAP transmission system can
derive no benefit from this wheeling arrangement. To be consistent with
the functional unbundling requirements, this wheeling arrangement
should belong to the generation/power merchant function.
Response: RMR agrees and has eliminated this item from the
numerator of the rate design calculation.
Comment: RMR transmission rate proposal does not include any
revenue credit for the lease of facilities that have been included in
the functionalized LAP transmission plant investment.
Response: RMR reviewed all revenue from rental of facilities, which
are included in the transmission plant investment. Such revenues are
about $30,000, annually. These revenues have been included as a revenue
credit in the numerator.
Comment: One commentor supports separating the cost of
subtransmission facilities from the transmission rate. Clearly these
facilities are not part of the bulk supply system, but are used to
serve local loads, and, therefore, should be paid for separately.
Response: RMR agrees and assigned the subtransmission to the
Federal Customers. The subtransmission system is used primarily for
delivery of Federal power to the Federal Customers. If a Transmission
Customer requires the use of the subtransmission system, an additional
facility-use charge will be assessed.
Comment: The primary reason for the increase in the transmission
rate was due to a change in the denominator. One customer recognized
that a large portion of this change was because some customers included
their Federal load in the transmission load projections they provided
to Western for the 1993 transmission rate. This overstated the
denominator. This commentor suggested that when submitting to FERC, RMR
should include data showing how the loads change by customer.
Response: The suggested information has been provided in the
supporting data to this Rate Order. The transmission rate has been
understated since 1994. Western has corrected the rate so that the
transmission revenue requirement will be collected.
Comment: One commentor supports RMR keeping its firm power rate
bundled, but is concerned that RMR may not meet the comparability
requirements of FERC Order No. 888 because it does not charge itself
for transmission service, including all wholesale power deliveries to
Preference Customers, the same rate as it will charge others for use of
the transmission system.
Response: Firm Federal power is transmitted as a network-type
service under existing bundled Firm Electric Service Contracts, and not
under Western's Tariff. RMR uses whatever power or transmission is
required to meet its Firm Electric Service Contract commitments, like
network transmission service.
RMR believes that it meets the comparability requirement of FERC
Order No. 888. In FERC Order No. 888-A, Section IV.C.b., it is
clarified that the transmission provider must ``take service'' under
its own tariff for third-party sales for comparability. RMR's merchant
function will take service under Western's Tariff and point-to-point
rates for any third-party sales.
FERC Order No. 888-A recognizes that existing contracts will not
necessarily be at the same rate as the transmission service offered
under the Tariff. However, the service can still be considered
comparable. RMR has shown in its rate design for this Rate Order that
the calculation of transmission costs for delivery to Federal Customers
is on the same basis as for other firm Transmission Customers.
Comment: Several commentors support RMR's phased-in approach to
reach its required transmission rate level, as a means to mitigate the
rate shock associated with the large rate increase.
Response: RMR proposed a three-step approach to implement the
transmission rate increase between April 1, 1998, and October 1, 1999.
Comment: The commentor commended Western for its thoughtful
approach in developing the proposed transmission rates and the thorough
public process associated with encouraging comment from affected
parties and interested members of the public.
Response: RMR appreciates the input from its customers during the
public process.
Ancillary Services Discussion
Six ancillary services will be offered by WACM; two of which are
required to be purchased by the LAP Transmission Customer. These two
are: (1) Scheduling, System Control, and Dispatch Service, and (2) VAR
Support. The remaining four ancillary services--Regulation, Energy
Imbalance Service, Spinning Reserves, and Supplemental Reserves--will
also be offered, but are subject to availability.
Sales of Regulation, Energy Imbalance Service, Spinning Reserves,
and Supplemental Reserves may be limited since Western has allocated
its power resources to preference entities under long-term commitments.
If WACM is unable to provide these services from its own resources, an
offer will be made to purchase the services and pass through these
costs to the customer, including an administrative charge.
The formula rates for ancillary services will be based on the costs
of WACM control area and are designed to recover only the costs
associated with providing the service(s).
The WACM, as of April 1, 1998, will have a single control office,
combining the offices that formerly controlled the Western Area Upper
Colorado control area (WAUC) and the Western Area Lower Missouri
control area (WALM). WACM Federal power resources consist of all the
LAP Federal power resources and a portion of the Salt Lake City Area-
Integrated Projects (SLCA-IP) Federal power resources.
Scheduling, System Control, and Dispatch Service: The costs for
providing Scheduling, System Control, and Dispatch Service for
Transmission Customers are included in the appropriate transmission
service rates. This service can be provided only by the control area
operator in which the transmission facilities are located. The formula
rates will be applied to all schedules for WACM non-transmission
customers.
The formula rate for Scheduling, System Control, and Dispatch is
based on the annual cost of all personnel and related cost involved in
providing the service for WACM. The annual cost is divided by the
number of schedules per year to derive a ``rate per schedule'' applied
per day. RMR's definition of a ``schedule'' is a specific request for
energy or transmission through, within, into, or out of WACM, per day.
The entity requesting the schedule is generally the entity responsible
for the scheduling charge, unless other arrangements are made.
RMR will accept any reasonable number of schedule changes over the
course of a day, without any additional charge, so that entities trying
to follow their loads closely may do so without penalty.
Based on FY 1996 data, the rate for WACM, effective April 1, 1998,
will be $25.71 per schedule per day.
Reactive Supply and Voltage Control Service from Generation
Sources: The formula rate for VAR Support is based upon Reclamation's
net generation plant
[[Page 16790]]
investment in WACM. Annual Fixed Charge Rates based on annual
generation-related O&M, A&GE, depreciation, and interest expenses for
LAP and for SLCA-IP are applied to Reclamation's net generation plant
investment to calculate annualized costs. The percentage of WACM
generation capacity that is utilized for VAR Support is then
identified. This percentage is applied to the annualized costs for LAP
and SLCA-IP, and those results summed to derive the annual revenue
requirement for VAR Support for WACM. The annual revenue requirement is
then divided by the WACM 12-cp load being provided VAR Support, to
yield a $/kW-year rate, which is divided by 12 months to yield a kW-
month rate. Based upon FY 1996 data, the WACM rate for VAR Support is
$0.112/kW-month.
Credit may be given to those customers with generators in the
control area providing WACM with VAR Support. Any crediting arrangement
must be documented in the customers' service agreements.
Regulation and Frequency Response Service: The formula rate for
Regulation is based upon the annualized cost of Reclamation's net plant
investment for regulating plants in WACM (the investment costs for
SLCA-IP regulating plants that will provide Regulation in the Western
Area Lower Colorado control area were not included). The net investment
costs were included for only those plants that are able to provide
regulating service--run-of-the-river plants were excluded because
regulation control is not possible from those plants. The same Annual
Fixed Charge Rates used in the VAR Support formula were used to convert
the LAP and SLCA-IP net plant investments to annual costs for
Regulation. The annual costs are divided by the nameplate capacity of
the applicable plants to yield an average cost per kilowatt for LAP and
SLCA-IP.
The amount of capacity used to provide Regulation service is
identified. For LAP, one-half of the percentage of the resource used to
provide Regulation is multiplied by the load in the control area
requiring Regulation. For SLCA-IP, historical operational experience
shows that the amount of capacity provided for the SLCA-IP load is 40
MW. The April 1, 1998, division of the SLCA-IP load into two control
areas, discussed previously, has been determined to represent a 50/50
split of the load, and therefore, the capacity amount applicable to the
WACM from SLCA-IP is 20 MW.
The average cost per kilowatt for LAP and SLCA-IP is then
multiplied by the appropriate amounts of capacity providing Regulation,
to yield the annual revenue requirements for Regulation. The annual
revenue requirements are then summed and divided by the load in the
control area requiring Regulation service. This yields a rate per kW-
year, which is divided by 12 months to calculate a rate per kW-month.
Based upon FY 1996 data, the WACM rate for Regulation is $0.147/kW-
month.
Federal Customers will receive a credit for Regulation on their
power bill if they receive Regulation from another source, or self-
supply it for their own load. Credit will also be given to those
customers who provide WACM with Regulation. These types of crediting
arrangements must be documented in the Transmission Customers' service
agreements.
Energy Imbalance Service: FERC established guidelines for Energy
Imbalance Service of +/-1.5 percent hourly deviation (3 percent
bandwidth) with a 2 MW minimum deviation, as in their view, anything
more or less than that could affect the reliability of the system. RMR
established the 3 percent bandwidth for Energy Imbalance Service to be
consistent with FERC.
RMR recognizes that metering inadequacies, revision of scheduling
practices, and unit control problems may initially hinder a customer's
ability to meet the 3 percent bandwidth. Therefore, RMR is phasing in
the Energy Imbalance Service bandwidth simultaneously with the
transmission service rate to allow a transition period; whereby,
customers may improve their equipment and scheduling practices.
Effective April 1, 1998, the bandwidth will be set at 6 percent (+/-3
percent deviation); effective October 1, 1998, the bandwidth will drop
to 5 percent (+/-2.5 percent); and effective October 1, 1999, the
bandwidth will be in compliance with the FERC-endorsed bandwidth of 3
percent (+/-1.5 percent). Deviation accounting will be completed
monthly on an hour-to-hour basis.
RMR reserves the right to assess negative excursions (under
deliveries) outside the bandwidth and occurring more than five times
per month, a penalty charge of 100 mills/kWh.
During normal water conditions, any positive excursions (over
deliveries) outside the bandwidth will be credited on the customer's
bill, lagged by 1 month. The credit will be 50 percent of the regional
average monthly price for non-firm purchases, provided that these over
deliveries do not impinge on WACM operations. For example, during times
of high water conditions, RMR will reserve the right to eliminate any
credits for over deliveries.
Spinning/Supplemental Reserves: Based upon the Post-1999 Resource
Study (July 1995), WACM has no long-term Reserves available beyond its
own internal requirements.
An offer will be made to purchase Reserves for a customer and pass
through that cost, plus an amount for administration.
When Reserves are called on for Emergency Use, RMR will assess a
charge for energy used, at the greater of 30 mills/kWh or the
prevailing market energy rate in the region. The customer would be
responsible for providing the transmission to get the Reserves to its
destination.
Ancillary Services Comments
RMR received written comments concerning the ancillary services
during the public comment and consultation period. These comments have
been paraphrased where appropriate, without compromising the meaning of
the comment. Certain comments were duplicative in nature, and were
combined. RMR's response follows each comment.
Comment: A commentor believes that the load determinants for
Regulation and VAR Support, as referenced on page 38 of the Customer
Brochure, are understated for the following reasons.
For VAR Support, RMR has not accounted for Missouri Basin Power
Pool, Tri-State, and CSU generation within the WALM control area.
Likewise, RMR has not accounted for Craig, Nucla, Qualifying
Facilities, small hydro, and other western Colorado generation that
will be located in WACM.
Since VAR Support is a required service, why did RMR remove Black
Hills Power and Light's (Black Hills) load from the denominator?
For Regulation, RMR has not accounted for all PacifiCorp, Tri-
State, municipal, and Rural Electric Association (REA) loads located in
the WALM control area. Likewise, RMR has not accounted for any non-
Federal, western Colorado, Tri-State, municipal and REA loads located
in WACM.
Response: Page 38 of RMR's Customer Brochure incorrectly identified
``Tri-State Direct (in WALM)'' with a number that was actually
representative of cumulative ``other'' load in WACM. RMR did, in fact,
include the loads that the commentor believes were omitted; i.e.,
Missouri Basin Power Pool, Tri-State, CSU, PacifiCorp, municipal, and
REA. RMR also accounted for the western Colorado generation that will
be located in WACM.
[[Page 16791]]
Based upon this commentor's statements, however, Western revisited
and reconfirmed the load denominator for both VAR Support and
Regulation service for the ``other'' load in the control area, and has
refined them to be 1,047,979 kW for Regulation and 1,538,608 kW for VAR
Support, as contrasted with the loads in the Customer Brochure of
1,407,917 kW for Regulation and 1,437,638 kW for VAR Support.
Black Hills' load was omitted from the VAR Support service load as
they cannot receive this service from a WACM generation source. Load
data for Black Hills were accounted for as part of the Regulation load,
as they are in WACM's control area and RMR has a specific contract with
Black Hills to provide them Regulation service. RMR also reassessed the
277 MW included in the Regulation load for Black Hills as RMR does not
provide Regulation for Black Hill's total load. Based upon bills
submitted in 1997, the average amount of load that RMR regulates for
Black Hills is 89 MW. In conjunction with this adjustment to Black
Hill's Regulation load, RMR included a $90,000 revenue credit for the
existing contract for Regulation service.
Comment: A commentor is concerned about the narrow bandwidth (+/-
1.5 percent) allowed for deviation from scheduled transactions,
maintaining that it will be extremely difficult to stay within this
bandwidth because of limitations and errors in metering, scheduling
practices, and unit control.
This same commentor also requests that generating entities within
the control area also be given the opportunity to participate with
Western in the provision of Energy Imbalance Service, rather than
merely taking the service from RMR as the control area operator.
Response: FERC has established guidelines for Energy Imbalance
Service of +/-1.5 percent deviation (or 3 percent bandwidth), as in
their view, anything more or less than that could affect the
reliability of the system. RMR established a bandwidth for Energy
Imbalance Service to be consistent with FERC and with what the industry
has been using as a standard.
RMR points out to its customers that FERC did establish a larger
minimum deviation of 2 megawatts (MW) in an attempt to meet the needs
of smaller customers. This minimum allows Transmission Customers with
load less than 133 MW to have more flexibility in the bandwidth.
However, RMR does recognize that some of its customers may construe
the 3 percent bandwidth as too narrow, from the perspective that there
are currently limitations in metering, scheduling practices, and unit
control. Therefore, RMR is phasing in the Energy Imbalance Service
bandwidth simultaneously with the transmission service rate to allow a
transition period; whereby, customers may improve their equipment and
revise their scheduling practices. Effective April 1, 1998, the
bandwidth will be set at 6 percent (+/-3 percent deviation); effective
October 1, 1998, the percentage bandwidth will drop to 5 percent (+/-
2.5 percent deviation); and effective October 1, 1999, the percentage
bandwidth will be in compliance with the FERC-endorsed bandwidth of 3
percent (+/-1.5 percent deviation).
Regarding participation in the provision of Energy Imbalance
Service by others in WACM, RMR asks that any proposals submitted to RMR
demonstrate the benefits to the control area in terms of Energy
Imbalance Service (deviation, inadvertent flow, and losses), and
reliability for operation of the control area.
Comment: A commentor recommends that the provision limiting
schedule changes be eliminated. They also recommend a more rigorous
definition of the term ``schedule'' as it is applied in this rate. The
commentor noted that it may be worthwhile to consider an exhibit to the
service agreement that would identify billable schedules.
Response: In its initial rate design, RMR developed its Scheduling,
System Control, and Dispatch Service rate and limited the number of
schedule changes to five times per day before any additional scheduling
charge would be assessed. Schedule changes equate to the use of
personnel and associated cost, and RMR was trying to both accommodate
the customer and recover the cost of doing business.
However, RMR has recognized that any limit on the number of
schedule changes per day may penalize entities trying to follow their
loads closely. Therefore, RMR will accept any reasonable number of
schedule changes over the course of the day without additional charges.
RMR's definition of a ``schedule'' is a specific request for energy
or transmission through, into, within, or out of WACM, per day. The
entity requesting the schedule is generally the entity responsible for
the scheduling charge, unless other arrangements are made.
The comment concerning inclusion of an exhibit to the individual
service agreements is outside the rate adjustment process; however, RMR
will consider the inclusion of this exhibit to the individual service
agreements identifying billable schedules.
Comment: A commentor asks that RMR and Upper Great Plains Region
(UGPR) be consistent on policy for Energy Imbalance Service.
Response: RMR and UGPR are separate regional offices of Western
within separate control areas, and as such, have disparate operational
requirements. Additionally, the UGPR operates with basically one
drainage basin, while LAP has five basins within its operational
control.
LAP's five basins allow for greater operational flexibility than
UGPR's main-stem system; e.g., during high water conditions, WACM would
be less likely to be forced to spill and potentially lose energy. RMR
has indicated that it would credit the customer for 50 percent of the
regional average monthly price for non-firm purchases in a scheduled
over delivery; however, RMR will reserve the right to eliminate credits
during times when over deliveries would impinge upon WACM operations.
RMR has revised its Energy Imbalance Service rate language accordingly.
Comment: A commentor expresses concern that care be taken to see
that all revenues for ancillary services are credited back to the firm
electric service rate.
Response: Western is developing procedures for proper accounting
classification of Open Access Transmission revenues. RMR will assure
that all revenues, including ancillary services, are incorporated in
the P-SMBP Power Repayment Study, and revenues will be applied pursuant
to DOE Order No. RA 6120.2.
Comment: A commentor wants to ensure that RMR views the ancillary
services as an integral component of the Federal Government's power
allocation. It is the commentor's position that the provision of any
generation-related ancillary services which interfere with the
statutory obligations of Western to dedicate its generation resources
to Federal Customers is statutorily prohibited. Specifically,
concerning Regulation and Reserves, Western should limit itself to
providing these services to non-Federal customers only after first
offering the resource to its Federal Customers. Otherwise, Western
should limit the offer of these services to the brokering of ancillary
services from third-party providers. Further, concerning Reserves and
the selling of short-term Reserves when available, Western should
affirm that if and when such Reserves are available on a short-term
basis, they will be offered to Federal Customers first.
[[Page 16792]]
Response: Western views the ancillary services as an integral
component of the Federal Government's power allocation and is not
changing this viewpoint with the advent of FERC Order No. 888. Western
will not take any actions that would compromise its ability to meet its
contractual obligations to its Federal Customers. RMR will continue to
provide all of the services so designated as approved in the Marketing
Plan.
While ancillary services were not specifically defined or offered
in the Marketing Plan, those services are presumed to be included in
the allocation and delivery of RMR's firm power resource. RMR has fully
allocated all firm resources through the Marketing Plan and currently
provides all of the required ancillary services for the Federal
Customers.
As stated previously, the RMR Post-1999 Resource Study ascertained
that there are no long-term Reserves available from WACM resources
beyond WACM internal requirements. Historically, when Western has had
non-firm, short-term, or surplus resources available for sale, they
have been sold on the open market. RMR has offered surplus energy first
to those with Firm Electric Service Contracts, but it is an option that
surplus energy be sold on the open market, as Western's UGPR and
Colorado River Storage Project Customer Service Center have done. The
Marketing Plan allows the sale of non-firm, short-term, or surplus
resources in Section B.3.c., Marketing Considerations.
RMR has engaged in the marketing of ancillary services prior to
this filing, as evidenced by RMR's provision of interconnected
operation service (shaping and storage service) for RMGC, and RMR's
provision of Regulation service for Black Hills. These products have
been offered to both preference and non-preference customers.
Comment: A commentor applauded RMR's stance that only the ancillary
services that are surplus to those required to meet Western's statutory
requirements would be offered for sale. The commentor agreed with RMR's
position regarding the purchase and pass through of costs for ancillary
services, when not available from a control area resource.
Response: RMR appreciates the comment.
Regulatory Flexibility Analysis
Pursuant to the Regulatory Flexibility Act of 1980 (5 U.S.C. 601-
612), each agency, when required by 5 U.S.C. 553 to publish a proposed
rule, is further required to prepare and make available for public
comment an initial regulatory flexibility analysis to describe the
impact of the proposed rule on small entities. In this instance, the
initiation of the LAP transmission rate and ancillary service rate
adjustment is related to non-regulatory services provided by Western at
a particular rate. Under 5 U.S.C. 601(2), rules of particular
applicability relating to rates or services are not considered rules
within the meaning of the Act. Since the LAP transmission rates and
ancillary service rates are of limited applicability, no flexibility
analysis is required.
Environmental Evaluation
In compliance with the National Environmental Policy Act (NEPA) of
1969, 42 U.S.C. 4321 et seq.; the Council on Environmental Quality
Regulations (40 CFR Parts 1500-1508); and DOE NEPA Regulations (10 CFR
Part 1021), Western has determined that this action is categorically
excluded from the preparation of an environmental assessment or an
environmental impact statement.
Executive Order 12866
DOE has determined that this is not a significant regulatory action
because it does not meet the criteria of Executive Order 12866, 58 FR
51735. Western has an exemption from centralized regulatory review
under Executive Order 12866; accordingly, no clearance of this notice
by the Office of Management and Budget is required.
Submission to Federal Energy Regulatory Commission
The formula 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.
Order
In view of the foregoing, and pursuant to the authority delegated
to me by the Secretary of Energy, I confirm, approve, and place into
effect on an interim basis, effective April 1, 1998, formula rates for
transmission and ancillary service under Rate Schedules L-NT1, L-FPT1,
L-NFPT1, L-AS1, L-AS2, L-AS3, L-AS4, L-AS5, and L-AS6. These schedules,
in total, supersede Rate Schedules L-T3 and L-T4. The rate schedules
shall remain in effect on an interim basis, pending FERC confirmation
and approval of them or substitute formula rates on a final basis
through March 31, 2003.
Dated: March 23, 1998.
Elizabeth A. Moler,
Deputy Secretary.
Rocky Mountain Region, Loveland Area Projects--Rate Schedule L-AS1
(Supersedes L-T3) Schedule 1 to Tariff April 1, 1998
Scheduling, System Control, and Dispatch Service
Applicable
This service is required to schedule the movement of power through,
out of, within, or into the Western Area Colorado Missouri control area
(WACM). The charges for Scheduling, System Control, and Dispatch
Service are to be based on the rate referred to below. The formula rate
used to calculate the charges for service under this schedule was
promulgated and may be modified pursuant to applicable Federal laws,
regulations, and policies.
The rate will be applied to all schedules for WACM non-transmission
customers. The Rocky Mountain Region (RMR) will accept any reasonable
number of schedule changes over the course of the day without any
additional charge.
The Loveland Area Projects charges for Scheduling, System Control,
and Dispatch Service may be modified upon written notice to the
customer. Any change to the charges for the Scheduling, System Control,
and Dispatch Service shall be as set forth in a revision to this rate
schedule promulgated pursuant to applicable Federal laws, regulations,
and policies and made part of the applicable service agreement. RMR
shall charge the non-transmission customer in accordance with the rate
then in effect.
Effective
The first day of the first full billing period beginning on or
after April 1, 1998, through March 31, 2003.
Formula Rate
[GRAPHIC] [TIFF OMITTED] TN06AP98.009
[[Page 16793]]
* * * * *
Rate
The rate to be in effect April 1, 1998, through September 30, 1998,
is $25.71 per schedule per day. This rate is based on the above formula
and on FY 1996 data. A recalculated rate will go into effect every
October based on the above formula and data.
Rate Schedule L-AS2 (Supersedes L-T3 and L-T4) Schedule 2 to Tariff
April 1, 1998
Reactive Supply and Voltage Control from Generation Sources Service
Applicable
In order to maintain transmission voltages on all transmission
facilities within acceptable limits, generation facilities under the
control of the Western Area Colorado Missouri control area (WACM) are
operated to produce or absorb reactive power. Thus, Reactive Supply and
Voltage Control from Generation Sources Service (VAR Support) must be
provided for each transaction on the transmission facilities. The
amount of VAR Support that must be supplied with respect to the
Customer's (Loveland Area Projects (LAP) Transmission Customers and
customers on others' transmission systems within the WACM) transaction
will be determined based on the VAR Support necessary to maintain
transmission voltages within limits that are generally accepted in the
region and consistently adhered to by WACM.
The Customer must purchase this service from the WACM operator. The
charges for such service will be based upon the rate referred to below.
The formula rate used to calculate the charges for service under
this schedule was promulgated and may be modified pursuant to
applicable Federal laws, regulations, and policies.
The LAP charges for VAR Support may be modified upon written notice
to the Customer. Any change to the charges for VAR Support shall be as
set forth in a revision to this rate schedule promulgated pursuant to
applicable Federal laws, regulations, and policies and made part of the
applicable service agreement. The Rocky Mountain Region shall charge
the Customer in accordance with the rate then in effect.
Credit may be given to those Customers with generators in the
control area providing WACM with VAR Support. Any crediting
arrangements must be documented in the customer's service agreement.
Effective
The first day of the first full billing period beginning on or
after April 1, 1998, through March 31, 2003.
Formula Rate
[GRAPHIC] [TIFF OMITTED] TN06AP98.010
* * * * *
Rate
The rate to be in effect April 1, 1998, through September 30, 1998,
is:
Monthly: $0.112/kW-month
Weekly: $0.026/kW-week
Daily: $0.004/kW-day
Hourly: 0.154 mills/kWh
This rate is based on the above formula and on FY 1996 financial
and load data. A recalculated rate will go into effect every October
based on the above formula and updated financial and load data.
Rate Schedule L-AS3 (Supersedes L-T3) Schedule 3 to Tariff April 1,
1998
Regulation and Frequency Response Service
Applicable
Regulation and Frequency Response Service (Regulation) is necessary
to provide for the continuous balancing of resources, generation, and
interchange, with load and for maintaining scheduled interconnection
frequency at sixty cycles per second (60 Hz). Regulation is
accomplished by committing on-line generation whose output is raised or
lowered, predominantly through the use of automatic generating control
equipment, as necessary to follow the moment-by-moment changes in load.
The obligation to maintain this balance between resources and load lies
with the Western Area Colorado Missouri control area (WACM) operator.
The Customer (Loveland Area Projects (LAP) Transmission Customers and
customers on others' transmission systems within WACM) must either
purchase this service from WACM or make alternative comparable
arrangements to satisfy its Regulation obligation. The charges for
Regulation are referred to below. The amount of Regulation will be set
forth in the service agreement.
The formula rate used to calculate the charges for service under
this schedule was promulgated and may be modified pursuant to
applicable Federal laws, regulations, and policies.
The LAP charges for Regulation may be modified upon written notice
to the Customer. Any change to the Regulation charges shall be as set
forth in a revision to this rate schedule promulgated pursuant to
applicable Federal laws, regulations, and policies and made part of the
applicable service agreement. The Rocky Mountain Region (RMR) shall
charge the Customer in accordance with the rate then in effect.
Customers will receive a credit for Regulation on their power bill
if they receive Regulation from another source, or self-supply it for
their own load. Credit will also be given to those Customers who
provide WACM with Regulation. These types of crediting arrangements
must be documented in the customer's service agreement.
Effective
The first day of the first full billing period beginning on or
after April 1, 1998, through March 31, 2003.
Formula Rate
* * * * *
[GRAPHIC] [TIFF OMITTED] TN06AP98.011
[[Page 16794]]
Rate
The rate to be in effect April 1, 1998, through September 30, 1998,
is:
Monthly: $0.147/kW-month
Weekly: $0.034/kW-week
Daily: $0.005/kW-day
This rate is based on the above formula and on FY 1996 financial
and load data. A recalculated rate will go into effect every October
based on the above formula and updated financial and load data.
If resources are not available from a WACM resource, RMR will offer
to purchase the Regulation and pass through the costs to the Customer,
plus an amount for administration.
Rate Schedule L-AS4, (Supersedes L-T3), Schedule 4 to Tariff, April 1,
1998.
Energy Imbalance Service
Applicable
Energy Imbalance Service is provided when a difference occurs
between the scheduled and the actual delivery of energy to a load
located within the Western Area Colorado Missouri control area (WACM)
over a single hour. The Customer (Loveland Area Projects (LAP)
Transmission Customers and customers on others' transmission system
within WACM) must either obtain this service from WACM or make
alternative comparable arrangements to satisfy its Energy Imbalance
Service obligation.
The WACM shall establish a deviation band of +/-3.0 percent (with a
minimum of 2 MW) of the scheduled transaction to be applied hourly to
any energy imbalance that occurs as a result of the Customer's
scheduled transaction(s). Deviation accounting will be completed
monthly on an hour-to-hour basis.
The formula rate used to calculate the charges for service under
this schedule was promulgated and may be modified pursuant to
applicable Federal laws, regulations, and policies.
The Energy Imbalance Service compensation may be modified upon
written notice to the Customer. Any change to the Customer compensation
for Energy Imbalance Service shall be as set forth in a revision to
this schedule promulgated pursuant to applicable Federal laws,
regulations, and policies and made part of the applicable service
agreement. The Rocky Mountain Region (RMR) shall charge the Customer in
accordance with the rate then in effect.
Effective
The first day of the first full billing period beginning on or
after April 1, 1998, through March 31, 2003.
Formula Rate
For negative excursions (under deliveries) outside the bandwidth
and occurring more than five times per month, RMR reserves the right to
assess a penalty charge of 100 mills/kWh.
For positive excursions (over deliveries) outside the bandwidth,
the Customer will be credited on the customer's bill, lagged by 1
month. The credit will be 50 percent of the regional average monthly
price for non-firm purchases, provided the over deliveries do not
impinge upon WACM operations. For example, during times of high water
or operating constraints, RMR reserves the right to eliminate credits
for over deliveries.
* * * * *
Rate
The bandwidth in effect April 1, 1998, through September 30, 1998,
is 6 percent (+/-3 percent hourly deviation).
Rate Schedule L-AS5 (Supersedes L-T3), Schedule 5 to Tariff, April 1,
1998.
Operating Reserve--Spinning Reserve Service
Applicable
Spinning Reserve Service (Reserves) is needed to serve load
immediately in the event of a system contingency. Reserves may be
provided by generating units that are on-line and loaded at less than
maximum output. The Customer (Loveland Area Projects (LAP) Transmission
Customers and customers on others' transmission system within Western
Area Colorado Missouri control area (WACM)) must either purchase this
service from WACM or make alternative comparable arrangements to
satisfy its Reserves obligation. The charges for Reserves are referred
to below. The amount of Reserves will be set forth in the service
agreement.
Effective
The first day of the first full billing period beginning on or
after April 1, 1998, through March 31, 2003.
Formula Rate
No long-term Reserves are available beyond internal WACM
requirements.
* * * * * *
Rate
There are no long-term Reserves available from WACM. An offer will
be made to purchase Reserves for a Customer and pass through the cost,
plus an amount for administration.
In the event that Reserves are called upon for Emergency Use, the
Rocky Mountain Region (RMR) will assess a charge for energy used, at
the greater of 30 mills/kWh or the prevailing market energy rate in the
region. The Customer would be responsible for providing the
transmission to get the Reserves to its destination.
Rate Schedule L-AS6 (Supersedes L-T3) Schedule 6 to Tariff April 1,
1998
Operating Reserve--Supplemental Reserve Service
Applicable
Supplemental Reserve Service (Reserves) is needed to serve load in
the event of a system contingency; however, it is not available
immediately to serve load but rather within a short period of time.
Reserves may be provided by generating units that are on-line but
unloaded, by quick-start generation or by interruptible load. The
Customer (Loveland Area Projects' Transmission Customers and customers
on others' transmission system within Western Area Colorado Missouri
control area (WACM)) must either purchase this service from WACM or
make alternative comparable arrangements to satisfy its Reserves
obligation. The charges for Reserves are referred to below. The amount
of Reserves will be set forth in the service agreement.
Effective
The first day of the first full billing period beginning on or
after April 1, 1998, through March 31, 2003.
Formula Rate
No long-term Reserves are available beyond internal WACM
requirements.
* * * * *
Rate
There are no long-term Reserves available from WACM. An offer will
be made to purchase Reserves for a Customer and pass through the cost,
plus an amount for administration.
In the event that Reserves are called upon for Emergency Use, the
Rocky Mountain Region will assess a charge for energy used, at the
greater of 30 mills/kWh or the prevailing market energy rate in the
region. The Customer would be responsible for providing the
transmission to get the Reserves to its destination.
Rate Schedule L-FPT1 (Supersedes L-T3) Schedule 7 to Tariff April 1,
1998
Long-Term Firm and Short-Term Point-to-Point Transmission Service
Applicable
The Transmission Customer shall compensate Rocky Mountain Region
(RMR) each month for Reserved Capacity pursuant to the applicable
[[Page 16795]]
Firm Point-to-Point Transmission Service Agreement and rates referred
to below. The formula rates used to calculate the charges for service
under this schedule were promulgated and may be modified pursuant to
applicable Federal laws, regulations, and policies.
RMR may modify the charges for Firm Point-to-Point Transmission
Service upon written notice to the Transmission Customer. Any change to
the charges to the Transmission Customer for Firm Point-to-Point
Transmission Service shall be as set forth in a revision to this rate
schedule promulgated pursuant to applicable Federal laws, regulations,
and policies and made part of the applicable service agreement. RMR
shall charge the Transmission Customer in accordance with the rate then
in effect.
Discounts
Three principal requirements apply to discounts for transmission
service as follows: (1) any offer of a discount made by RMR must be
announced to all Eligible Customers solely by posting on the Open
Access Same-Time Information System (OASIS), (2) any Customer-initiated
requests for discounts, including requests for use by one's wholesale
merchant or an affiliate's use, must occur solely by posting on the
OASIS, and (3) once a discount is negotiated, details must be
immediately posted on the OASIS. For any discount agreed upon for
service on a path, from Point(s) of Receipt to Point(s) of Delivery,
RMR must offer the same discounted transmission service rate for the
same time period to all Eligible Customers on all unconstrained
transmission paths that go to the same point(s) of delivery on the
Transmission System.
Effective
The first day of the first full billing period beginning on or
after April 1, 1998, through March 31, 2003.
Formula Rate
If a Transmission Customer requires use of subtransmission
facilities, a specific facility use charge will be assessed in addition
to this formula rate.
* * * * *
[GRAPHIC] [TIFF OMITTED] TN06AP98.012
Rate
The rate to be in effect April 1, 1998, through September 30, 1998,
is as follows.
Maximum of:
Yearly: $27.84/kW of reserved capacity per year
Monthly: $2.32/kW of reserved capacity per month
Weekly: $0.54/kW of reserved capacity per week
Daily: $0.08/kW of reserved capacity per day
This rate is based on the above formula and FY 1996 data. A
recalculated rate will go into effect every October based on the above
formula and updated financial and load data.
Rate Schedule L-NFPT1 (Supersedes L-T4) Schedule 8 to Tariff April 1,
1998
Non-Firm Point-to-Point Transmission Service
Applicable
The Transmission Customer shall compensate Rocky Mountain Region
(RMR) for Non-Firm Point-to-Point Transmission Service pursuant to the
applicable Non-Firm Point-to-Point Transmission Service Agreement and
rate referred to below. The formula rates used to calculate the charges
for service under this schedule were promulgated and may be modified
pursuant to applicable Federal laws, regulations, and policies.
RMR may modify the charges for Non-Firm Point-to-Point Transmission
Service upon written notice to the Transmission Customer. Any change to
the charges to the Transmission Customer for Non-Firm Point-to-Point
Transmission Service shall be as set forth in a revision to this rate
schedule promulgated pursuant to applicable Federal laws, regulations,
and policies and made part of the applicable service agreement. RMR
shall charge the Transmission Customer in accordance with the rate then
in effect.
Discounts
Three principal requirements apply to discounts for transmission
service as follows: (1) any offer of a discount made by RMR must be
announced to all Eligible Customers solely by posting on the Open
Access Same-Time Information System (OASIS), (2) any Customer-initiated
requests for discounts, including requests for use by one's wholesale
merchant or an affiliate's use, must occur solely by posting on the
OASIS, and (3) once a discount is negotiated, details must be
immediately posted on the OASIS. For any discount agreed upon for
service on a path, from Point(s) of Receipt to Point(s) of Delivery,
RMR must offer the same discounted transmission service rate for the
same time period to all Eligible Customers on all unconstrained
transmission paths that go to the same point(s) of delivery on the
Transmission System.
Effective
The first day of the first full billing period beginning on or
after April 1, 1998, through March 31, 2003.
Formula Rate
* * * * *
[GRAPHIC] [TIFF OMITTED] TN06AP98.013
Rate
The rate to be in effect April 1, 1998, through September 30, 1998,
is:
Maximum of:
Monthly: $2.32/kW of reserved capacity per month
Weekly: $0.54/kW of reserved capacity per week
Daily: $0.08/kW of reserved capacity per day
Hourly: 3.33 mills/kWh
This rate is based on the above formula and FY 1996 data. A
recalculated rate will go into effect every October based on the above
formula and updated financial and load data.
Rate Schedule L-NT1 (Supersedes L-T3) Attachment H to Tariff April 1,
1998
Annual Transmission Revenue Requirement for Network Integration
Transmission Service
Applicable
The Transmission Customer shall compensate the Rocky Mountain
Region (RMR) each month for Network Transmission Service pursuant to
the applicable Network Integration Service Agreement and annual revenue
requirement referred to below. The formula for the annual revenue
requirement used to calculate the charges for this service under this
[[Page 16796]]
schedule was promulgated and may be modified pursuant to applicable
Federal laws, regulations, and policies.
RMR may modify the charges for Network Integration Transmission
Service upon written notice to the Transmission Customer. Any change to
the charges to the Transmission Customer for Network Integration
Transmission Service shall be as set forth in a revision to this rate
schedule promulgated pursuant to applicable Federal laws, regulations,
and policies and made part of the applicable service agreement. RMR
shall charge the Transmission Customer in accordance with the revenue
requirement then in effect.
Effective
The first day of the first full billing period beginning on or
after April 1, 1998, through March 31, 2003.
Formula Rate
[GRAPHIC] [TIFF OMITTED] TN06AP98.014
If a Transmission Customer requires use of subtransmission
facilities, a specific facility use charge will be assessed in addition
to this formula rate.
If an existing Transmission Customer elects to retain its
Transmission Contract and the contract terms are payment on an energy
basis, the capacity-unit rate under the formula rate will be converted
to an energy-unit rate based on the individual customer's total load
factor.
* * * * *
Rate
The revenue requirement in effect April 1, 1998, through September
30, 1998, is $31,555,162. This revenue requirement is based on the
above formula and FY 1996 data. A recalculated revenue requirement will
go into effect every October based on the above formula and updated
financial and load data.
[FR Doc. 98-8938 Filed 4-3-98; 8:45 am]
BILLING CODE 6450-01-P
