[Federal Register Volume 69, Number 7 (Monday, January 12, 2004)]
[Notices]
[Pages 1723-1738]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 04-575]


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DEPARTMENT OF ENERGY

Western Area Power Administration


Loveland Area Projects Transmission and Ancillary Services--Rate 
Order No. WAPA-106

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of Rate Order.

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

SUMMARY: Notice is given of the confirmation and approval by the Deputy 
Secretary of the Department of Energy (DOE) of Rate Order No. WAPA-106 
and Rate Schedules L-NT1, L-FPT1, L-NFPT1, L-AS1, L-AS2, L-AS3, L-AS4, 
L-AS5, L-AS6, and L-AS7 placing provisional rates for the Loveland Area 
Projects (LAP) transmission and ancillary services of the Western Area 
Power Administration (Western) into effect on an interim basis. The 
provisional rates will provide sufficient revenue to pay all annual 
costs, including interest expense, and repayment of required investment 
within the allowable period.

DATES: The provisional rates will be placed into effect on an interim 
basis on March 1, 2004, and will be in effect until the Federal Energy 
Regulatory Commission (Commission) confirms, approves, and places the 
provisional rates into effect on a final basis for a 5-year period 
ending February 28, 2009, or until superseded.

FOR FURTHER INFORMATION CONTACT: Mr. Daniel T. Payton, Rates Manager, 
Rocky Mountain Customer Service Region, Western Area Power 
Administration, 5555 E. Crossroads Boulevard, Loveland, CO 80538, 
telephone (970) 461-7442, e-mail [email protected].

SUPPLEMENTARY INFORMATION: The Deputy Secretary of Energy approved Rate 
Schedules L-NT1, L-FPT1, L-NFPT1, L-AS1, L-AS2, L-AS3, L-AS4, L-AS5, 
and L-AS6 on March 23, 1998 (Rate Order No. WAPA-80, 63 FR 16778, April 
6, 1998); and the Commission confirmed and approved the rate schedules 
on July 21, 1998, under FERC Docket No. EF98-5181-000 (84 FERC 61,066). 
The rate schedule for Energy Imbalance Service was revised and approved 
by the Secretary on May 30, 2002 (Rate Order No. WAPA-97, 67 FR 39970, 
June 11, 2002), through March 31, 2003.
    Additionally, Western has two existing rate schedules for Rocky 
Mountain Customer Service Region (RMR) services outside Western's Open 
Access Transmission Tariff (Tariff) that were approved for short-term 
service by Western's Administrator. These are Rate Schedule L-LO1, 
Transmission Losses Service, effective October 8, 2000, and Rate 
Schedule L-US1, Unauthorized Use of Transmission and Control Area 
Services, effective June 15, 2001. These rates, as well as those under 
the Tariff and listed above, were extended through March 31, 2004.
    Western will replace Rate Schedule L-LO1 with Rate Schedule L-AS7 
in this rate action. Rate Schedule L-US1 has been incorporated into 
revised Rate Schedules L-FPT1, L-NFPT1, and L-AS2 that are part of this 
rate action. Rate Schedule L-US1 will terminate upon the effective date 
of this rate order.
    There are no significant changes to the formula-based rate 
methodology for the transmission rates. Western is proposing changes 
for the formula-based rates for ancillary services. Rates for these 
services will be recalculated each year to incorporate the most recent 
financial and load information and will be applicable to all 
transmission and ancillary services customers.

Provisional Rates for LAP Transmission Service

    The provisional rates in Rate Schedules L-NT1, L-FPT1, and L-NFPT1 
for LAP transmission services are based on a revenue requirement that 
recovers (1) the LAP Transmission System costs for facilities 
associated with providing all transmission services; and (2) the non-
facility costs allocated to transmission services. These provisional 
firm and nonfirm LAP transmission service rates include the costs for 
scheduling, system control, and dispatch service needed to provide the 
transmission service. The provisional rates are applicable to existing 
network, firm and nonfirm LAP transmission services, and future 
transmission services.

Provisional Rates for Ancillary Services

    Western will provide seven ancillary services consistent with FERC 
Order No. 888. Of the seven ancillary services offered by Western, two 
are services which must be offered by the transmission provider or 
control area operator, and must be taken by the transmission customer. 
These are: (1) Scheduling, System Control, and Dispatch Service, and 
(2) Reactive Supply and Voltage Control Service from Generation Sources 
(VAR Support). The remaining five ancillary services, Regulation and 
Frequency Response Service (Regulation), Energy Imbalance Service, 
Spinning Reserves Service, Supplemental Reserves Service, and 
Transmission Losses Service, will be offered by Western, but the 
customer may also self-provide or purchase these services from another 
entity. The cost

[[Page 1724]]

associated with Scheduling, System Control, and Dispatch Service is 
included in the appropriate transmission service rate.
    The provisional rates for LAP transmission and ancillary services 
rates are developed pursuant to the Department of Energy Organization 
Act (42 U.S.C. 7101-7352), through which the power marketing functions 
of the Secretary of the Interior and the Bureau of Reclamation under 
the Reclamation Act of 1902 (ch. 1093, 32 Stat. 388), as amended and 
supplemented by subsequent enactments, particularly section 9(c) of the 
Reclamation Project Act of 1939 (43 U.S.C. 485h(c)), and other acts 
specifically applicable to the project involved, were transferred to 
and vested in the Secretary of Energy.
    By Delegation Order No. 00-037.00, approved December 6, 2001, the 
Secretary of Energy delegated (1) The authority to develop power and 
transmission rates on a nonexclusive basis to Western's Administrator; 
(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 Commission. Existing DOE procedures for 
public participation in power rate adjustments (10 CFR 903) became 
effective on September 18, 1985 (50 FR 37835).
    Rate Order No. WAPA-106, confirming, approving, and placing the 
proposed LAP transmission and ancillary services rates into effect on 
an interim basis, is issued, and new Rate Schedules L-NT1, L-FPT1, L-
NFPT1, L-AS1, L-AS2, L-AS3, L-AS4, L-AS5, L-AS6, and L-AS7 will be 
submitted promptly to the Commission for confirmation and approval on a 
final basis.

    Dated: December 30, 2003.
Kyle E. McSlarrow,
Deputy Secretary.

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 Delegation Order No. 00-037.00 approved December 6, 2001, the 
Secretary delegated: (1) The authority to develop power and 
transmission rates on a non-exclusive basis to Western's Administrator; 
(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 Commission.
    Existing DOE procedures for public participation in power rate 
adjustments are found in 10 CFR 903. Filing Requirements and Procedures 
for Approving the Rates of Federal Power Marketing Administrations by 
the Commission are found in 18 CFR 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 peak average
                                          of customers' loads,
                                          coincident with the LAP
                                          Transmission System peak.
CRSP...................................  Colorado River Storage Project.
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).
Federal Customers......................  Loveland Area Projects (LAP)
                                          customers taking delivery of
                                          long-term firm service under
                                          Firm Electric Service
                                          Contracts, project use, and
                                          special use contracts.
Fry-Ark................................  Fryingpan-Arkansas Project.
FY.....................................  Fiscal Year.
kW.....................................  Kilowatt; 1,000 watts.
kWh....................................  Kilowatt-hour; the common unit
                                          of electric energy, equal to 1
                                          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 coincident with
                                          Western's monthly transmission
                                          system peak, expressed as a
                                          ratio.
LSE....................................  Load-Serving Entity is an
                                          entity within the control area
                                          serving load.
Long-Term Firm Point-to-Point            Annual firm point-to-point
 Transmission Service.                    transmission service
                                          reservation with 12
                                          consecutive equal monthly
                                          amounts.
mill...................................  Unit of monetary value equal to
                                          .001 of a U.S. dollar; i.e.,
                                          \1/10\/th 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.
MW.....................................  Megawatt; equal to 1,000 kW or
                                          1,000,000 watts.
Network Integration Transmission         Firm Transmission Service for
 Service.                                 the delivery of capacity and
                                          energy from designated network
                                          resources to designated
                                          network loads.
Non-Firm Point-to-Point Transmission     Point-to-Point Transmission
 Service.                                 Service reserved on an as-
                                          available basis for periods
                                          ranging from 1 hour to 1
                                          month.
OASIS..................................  Open Access Same-Time
                                          Information System.
P-SMBP--WD.............................  Pick-Sloan Missouri Basin
                                          Project--Western Division.
RMR....................................  Rocky Mountain Customer Service
                                          Region.
Service Agreement......................  The initial agreement and any
                                          amendments or supplements
                                          entered into by the
                                          Transmission Customer and
                                          Western for service under the
                                          Tariff.
Short-Term Firm Point-to-Point           Firm point-to-point
 Transmission Service.                    transmission service for
                                          duration of less than 12
                                          consecutive months.
SSG-WI.................................  Seams Steering Group-Western
                                          Interconnection.
Tariff.................................  Western Area Power
                                          Administration, Open Access
                                          Transmission Service Tariff,
                                          Docket No. NJ-98-1-00.

[[Page 1725]]

 
Transmission Customer..................  The RMR customer taking network
                                          or point-to-point transmission
                                          service.
WACM...................................  Western Area Colorado Missouri
                                          control area.
WECC...................................  Western Electricity
                                          Coordinating Council.
------------------------------------------------------------------------

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 March 1, 2004, and will be in effect pending the Commission's 
approval of them or substitute formula rates on a final basis through 
February 28, 2009, or until superseded. These formula rates will be 
applied under existing transmission contracts and Western's Tariff. 
Western will replace existing Rate Schedules L-NT1, L-FPT1, L-NFPT1, L-
AS1, L-AS2, L-AS3, L-AS4, L-AS5, and L-AS6 with these new rate 
schedules for service on the LAP system.
    Additionally, Western has two existing rate schedules for ancillary 
services outside the Tariff that were approved for short-term service 
by Western's Administrator. These are Rate Schedule L-LO1, Transmission 
Losses Service, effective October 8, 2000, and Rate Schedule L-US1, 
Unauthorized Use of Transmission and Control Area Services, effective 
June 15, 2001. These rates, as well as those under the Tariff and 
listed above, were extended through March 31, 2004.
    Western will replace existing Rate Schedule L-LO1 with Rate 
Schedule L-AS7 in this rate action. Existing Rate Schedule L-US1 has 
been incorporated into revised Rate Schedules L-FPT1, L-NFPT1, and L-
AS2 that are part of this rate action. Rate Schedule L-US1 will 
terminate upon the effective date of this rate order.
    There are no significant changes to the formula-based rate 
methodology for the transmission rates. Western is proposing changes 
for the formula-based rates for ancillary services. Rates for these 
services will be recalculated each year to incorporate the most recent 
financial and load information and will be applicable to all 
transmission and ancillary services customers.

Public Notice and Comment

    Western has followed the Procedures for Public Participation in 
Power and Transmission Rate Adjustments and Extensions, 10 CFR 903, in 
the development of these formula rates and schedules.
    The following summarizes the steps Western took to ensure 
involvement of interested parties in the rate process:
    1. On May 19, 2003, Western held an informal Public Information 
Meeting with interested parties to discuss RMR's proposed rates for 
transmission and ancillary services. Western posted all information 
presented at the informal Public Information Meeting on its Web site at 
http://www.wapa.gov/rm/rm.htm.
    2. RMR published a Federal Register notice on June 13, 2003 (68 FR 
35398), 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 June 18, 2003, RMR sent a letter to all interested parties 
providing them with a copy of the Federal Register notice published on 
June 13, 2003 (68 FR 35398).
    4. On July 14-15, 2003, Western held its Public Information Forums 
in Denver, Colorado, and Lincoln, Nebraska, respectively, where Western 
representatives explained the need for the rate adjustment in detail 
and answered questions from interested parties.
    5. On August 6, 2003, Western held a Public Comment Forum in 
Denver, Colorado, to provide the public an opportunity to comment for 
the record. Seven individuals commented at this forum.
    6. On September 9, 2003, Western posted on its Web site answers to 
16 questions posed by a coalition representing wind generation 
proponents.
    7. Twenty-five parties submitted written comments during the 90-day 
Consultation and Comment Period. The Consultation and Comment Period 
ended on September 11, 2003. All comments have been considered in the 
preparation of this rate order.

Comments

    Representatives of the following organizations made oral comments:

American Wind Energy Association, Lakewood, Colorado;
Black Hills Power Company, Rapid City, South Dakota;
Lysco, New Brunswick, Ontario;
Municipal Energy Agency of Nebraska, Lincoln, Nebraska;
National Renewable Energy Laboratory, Golden, Colorado;
Nipco California;
Oak Ridge National Laboratory, Oak Ridge, Tennessee;
PanAero Corporation, Englewood, Colorado;
Tri-State Generation and Transmission Association, Inc., Westminster, 
Colorado;
Xcel Energy, Minneapolis, Minnesota.

    The following organizations submitted written comments:
American Wind Energy Association, Lakewood, Colorado;
Basin Electric Power Cooperative, Inc., Bismarck, North Dakota;
Black Hills Power Company, Rapid City, South Dakota;
Broken Bow Municipal Utilities, Broken Bow, Nebraska;
City of Alliance, Nebraska;
City of Aspen, Colorado;
City of Bridgeport, Nebraska;
City of Burwell, Nebraska;
City of Curtis, Nebraska;
City of Gering, Nebraska;
City of Gillette, Wyoming;
City of Gunnison, Colorado;
City of Mitchell, Nebraska;
City of Wood River, Nebraska;
Loveland Area Customers Association;
Mni Sose Intertribal Water Rights Coalition, Inc., Rapid City, South 
Dakota;
Municipal Energy Agency of Nebraska, Lincoln, Nebraska;
Oak Ridge National Laboratory, Oak Ridge, Tennessee;
PanAero Corporation, Englewood, Colorado;
Platte River Power Authority, Fort Collins, Colorado;
State of South Dakota;
Town of Lyons, Colorado;
Tri-State Generation and Transmission Association, Inc., Westminster, 
Colorado;
Village of Shickley, Nebraska;
Western Interstate Energy Board, Denver, 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 P-
SMBP--WD and the Fryingpan-Arkansas Project (Fry-Ark). 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 3,473 miles (5,589 circuit 
kilometers) and 79 substations.
    Western will offer ancillary services from Western Area Colorado 
Missouri control area (WACM) resources, which represent a combination 
of some CRSP generation resources and all LAP generation resources.

P-SMBP--WD

    The initial stages of the Missouri River Basin Project were 
authorized by

[[Page 1726]]

Section 9 of the Flood Control Act of December 22, 1944 (Pub. L. 534, 
58 Stat. 877, 891). The Missouri River Basin Project, later renamed the 
Pick-Sloan Missouri Basin Program (P-SMBP) to honor its two principal 
authors, has been under construction since 1944. The P-SMBP encompasses 
a comprehensive program of flood control, navigation improvement, 
irrigation, municipal and industrial (M&I) 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 powerplants on the Wind River; and Yellowtail Powerplant on the 
Big Horn River.
    In the Colorado-Big Thompson Project there are also six 
powerplants: Green Mountain Powerplant on the Blue River is on the West 
Slope of the Rocky Mountains; and Marys Lake, Estes, Pole Hill, 
Flatiron, and Big Thompson powerplants on the East Slope of the 
Continental Divide.
    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.

Fry-Ark

    The Fry-Ark is a transmountain diversion development in 
southeastern Colorado authorized by the Act of Congress on August 16, 
1962 (Pub. L. 87-590, 76 Stat. 389, as amended by Title XI of the Act 
of Congress on October 27, 1974 (Pub. L. 93-493, 88 Stat. 1486, 1497). 
The Fry-Ark diverts water from the Fryingpan River and other 
tributaries of the Roaring Fork River in the Colorado River Basin on 
the West Slope of the Rocky Mountains to the Arkansas River on the East 
Slope of the Continental Divide. The water diverted from the West 
Slope, together with regulated Arkansas River water, provides 
supplemental irrigation, M&I water supplies, and produces hydroelectric 
power. Flood control, fish and wildlife enhancement, and recreation are 
other important purposes of Fry-Ark. The only generating facility in 
Fry-Ark is the Mt. Elbert Pumped-Storage Powerplant on the East Slope 
of the Rocky Mountains.

CRSP

    CRSP was authorized by the Colorado River Storage Project Act, ch. 
203, 70 Stat. 105, on April 11, 1956. 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 CRSP in WACM 
is the territory north of Shiprock, New Mexico. CRSP hydroelectric 
facilities providing ancillary services for WACM are the Aspinall Unit 
(formerly Curecanti) and part of the Glen Canyon Powerplant. The 
southern portion of CRSP is operated by Western's Desert Southwest 
Customer Service Region in Phoenix, Arizona.

LAP Transmission Service

    RMR prepared a transmission service rate study based on the 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. 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 customers notice of changes in rates prior to October 1 of 
each year.
    RMR will continue to bundle transmission service for delivery of 
LAP long-term firm Federal power to Federal Customers in the firm power 
rate under existing contracts that expire in 2024. The transmission 
rates include the cost of Scheduling, System Control, and Dispatch 
Service.

System Augmentation

    Requests for credits for transmission augmentation were made in 
April 1999 by four entities: Cheyenne Light, Fuel, and Power Company; 
Platte River Power Authority; Tri-State Generation and Transmission 
Association, Inc.; and Wyoming Municipal Power Agency. These requests 
were resolved as follows:
    1. Cheyenne Light, Fuel, and Power Company's request was denied in 
1999.
    2. Based upon further discussion, Platte River Power Authority 
rescinded its request in 2003.
    3. Augmentation credits are being discussed with Tri-State 
Generation and Transmission Association, Inc., and will be included in 
the annual revenue requirement, if granted.
    4. Western purchased the Big George Substation from Wyoming 
Municipal Power Agency in 2000, and eliminated the need for 
augmentation credits.
    Western evaluated 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.

    An estimate for augmentation is included in Western's current 
revenue requirement for transmission service.

Ancillary Services

    RMR will offer seven ancillary services to all customers. The seven 
ancillary services are: (1) Scheduling, System Control, and Dispatch 
Service; (2) VAR Support; (3) Regulation; (4) Energy Imbalance Service; 
(5) Spinning Reserves Service; (6) Supplemental Reserves Service; and 
(7) Transmission Losses Service. 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 costs.
    In its Notice of Proposed Rates published in the Federal Register 
on June 13, 2003, RMR's rate proposal for Regulation had two 
components. The first component's charge was load-based, where the 
customer would be charged for Regulation based upon its 12-cp load 
calculation. The second component's charge was capacity-based, 
specifically addressing intermittent renewable resources. The charge 
was designed to compensate WACM for the lack of predictability and 
control of intermittent renewable resources.
    However, due to a significant number of comments received during 
the public process, Western has withdrawn the second component of the 
Regulation rate from this final Notice of Rate Order. Western plans to 
engage in a dialogue with the public concerning the Regulation rate and 
its design in early 2004, after which time Western will reopen the 
Regulation rate for another

[[Page 1727]]

separate public process to continue through the spring and summer of 
2004.

Comparison of Existing and Provisional Rates for Transmission and 
Ancillary Services

    The following table displays a comparison of existing rates and the 
provisional formula rates using FY 2002 data. These rates will be 
recalculated annually based on updated financial and load data.

------------------------------------------------------------------------
                                  Existing rate       Provisional rate
                                schedule and rate     schedule and rate
      Class of service        effective October 1,   effective March 1,
                                      2003                  2004
------------------------------------------------------------------------
Network Transmission Service  L-NT1...............  L-NT1.
                              Load ratio share of   Load ratio share of
                               1/12 of the revenue   1/12 of the revenue
                               requirement of        requirement of
                               $38,776,237.          $38,776,237.
Firm Point-to-Point           L-FPT1..............  L-FPT1.
 Transmission Service.        $2.68/kW-month......  $2.68/kW-month;
                                                     Unauthorized Use
                                                     Penalty will apply.
Non-Firm Point-to-Point       L-NFPT1.............  L-NFPT1.
 Transmission Service.        Maximum of 3.75       Maximum of 3.75
                               mills/kWh.            mills/kWh;
                                                     Unauthorized Use
                                                     Penalty will apply.
Scheduling, System Control,   L-AS1...............  L-AS1.
 and Dispatch Service.        $40.90 per schedule   $25.22 per
                               per day for non-      electronic tag per
                               transmission          day for non-
                               customers.            transmission
                                                     customers.
Reactive Supply and Voltage   L-AS2...............  L-AS2.
 Control Service from         $0.106/kW-month.....  $0.106/kW-month;
 Generation Sources.                                 Unauthorized use
                                                     penalty will apply.
Regulation and Frequency      L-AS3...............  L-AS3.
 Response Service.            $0.164/kW-month.....  $0.175/kW-month.
Energy Imbalance Service....  L-AS4...............  L-AS4.
                              Bandwidth of +/-5%    Bandwidth of +/-5%
                               with an outside-the-  with an outside-the-
                               bandwidth penalty     bandwidth penalty
                               of 50%, with LAP      of 25%, with LAP
                               weighted average      weighted average
                               hourly real-time      hourly real-time
                               sale and purchase     sale and purchase
                               pricing applied.      pricing applied.
                               Minimum deviation     Minimum deviation
                               of 2 MW.              of 4 MW.
Operating Reserves Service--  L-AS5, L-AS6........  L-AS5, L-AS6.
 Spinning and Supplemental.   Long-term reserves    Long-term reserves
                               are not available     are not available
                               from WACM. Reserves   from WACM. Reserves
                               may be provided on    may be provided on
                               a pass-through        a pass-through
                               cost, plus an         cost, plus an
                               amount for            amount for
                               administration.       administration.
Transmission Losses Service.  L-LO1...............  L-AS7.
                              Transmission losses   Transmission losses
                               may be settled        may be settled
                               either financially    either financially
                               or with energy.       or with energy.
                               Insufficient losses   Insufficient losses
                               supplied will be      supplied will be
                               settled financially   settled financially
                               by default.           by default.
                              Prescheduled          All customers will
                               transactions must     have the option to
                               have losses           return the loss
                               delivered             obligation for both
                               concurrently; real-   prescheduled and
                               time transactions     real-time
                               can return the        transactions 7 days
                               losses 7 days         later, same
                               later, same profile.  profile.
                              A 10% administration  Pricing used is LAP
                               fee will be applied   weighted average
                               against the amount    hourly real-time
                               of the customer's     purchase price.
                               bill.
                              Pricing used is Palo
                               Verde indices, on-
                               and off-peak.
Unauthorized Use of           L-US1...............  Incorporated into
 Transmission and Control     Penalized 150% of      Rate Schedules L-
 Area Services.                demand charge, with   FPT1, L-NFPT1, and
                               a maximum of          L-AS2. Penalized
                               monthly service,      150% of demand
                               against overruns of   charge, with a
                               reserved capacity.    maximum of monthly
                                                     service, against
                                                     overruns of
                                                     reserved capacity.
------------------------------------------------------------------------

Certification of Rates

    Western's 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

    RMR will implement the charges for network and point-to-point 
transmission service on March 1, 2004. 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 increase the capacity available for transmission. 
The formula is:
[GRAPHIC] [TIFF OMITTED] TN12JA04.051


[[Page 1728]]


    The Transmission Expenses Which Increase Transmission System 
Capacity will include credits paid to Transmission Customers for their 
augmentation of the LAP Transmission System. Crediting arrangements 
will be addressed in the individual service agreements, and appropriate 
adjustments will be made in subsequent rate calculations.
    Miscellaneous Revenue Credits may include, but 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. During the period October 1, 2001, through September 30, 
2002, the annual non-firm point-to-point transmission service credit is 
estimated to be $2,510,181, based on non-firm transmission sales made 
on the LAP Transmission System; the annual credit for short-term firm 
transmission sales is estimated to be $4,309,440; credits for 
scheduling service are estimated to be $180,600; and the credit for 
facility use charges is $0.
    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

    The formula applied to FY 2002 data is:

$45,276,458 = 19.812% x $228,530,479

    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, sub-transmission, 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 
``sub-transmission'' and ``distribution'' were allocated to LAP Federal 
Customers. The LAP sub-transmission system is used primarily for 
delivery of Federal power to Federal Customers. If a Transmission 
Customer requires the use of the sub-transmission system, an additional 
facility-use charge will be assessed. All costs of Fry-Ark were 
considered generation-related and therefore, included with other 
generation-related costs 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 the 230-kV transmission lines. In addition, a 
portion of the communication and maintenance facilities was included in 
the investment costs for transmission.
    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] TN12JA04.052

    The formula applied to FY 2002 data is:
    [GRAPHIC] [TIFF OMITTED] TN12JA04.053
    
    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.
    LAP 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 (12-cp) is calculated as 
follows, based upon 2002 data and known and measurable changes:

------------------------------------------------------------------------
                                                               kW
------------------------------------------------------------------------
Federal Customers.....................................           604,640
Network Transmission Customers........................           522,496
                                                       -----------------
    Subtotal..........................................         1,127,136
 
Point-to-Point Reserved Capacity......................            79,635
                                                       -----------------
    LAP Transmission System Total Load................         1,206,771
------------------------------------------------------------------------

    This LAP Transmission System Total Load for each month is derived 
as follows:
    1. Sum the hourly individual revenue meter readings for network 
delivery points on the LAP Transmission System to find the LAP system 
peak hour.
    2. Add the Federal Customers' entitlements that do not receive LAP 
auxiliary transmission.
    3. Add the reserved capacity for point-to-point customers.
    Network Integration Transmission Service: The monthly charge for 
Network Integration 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

[[Page 1729]]

the LAP Transmission System Total Load, which will be calculated on a 
rolling average 12-cp basis.
    The customer's network load is derived as follows:
    1. Identify the LAP Transmission System's peak hour for each month.
    2. Calculate the total delivery to each individual Network 
Integration Transmission Service customer for the 12 monthly peak 
hours.
    3. Identify the part of the total delivery associated with each 
customer's monthly LAP entitlement.
    4. Identify the network delivery (total delivery less monthly LAP 
entitlements) during each of the 12 monthly peaks.
    5. Sum the 12 monthly peaks and divide by 12 months to derive the 
average 12 cp for each Network Transmission Service customer.
    Firm Point-to-Point Transmission Service: The rate for Firm Point-
to-Point Transmission Service is the Annual Transmission Revenue 
Requirement, divided by the LAP Transmission System Total Load. Firm 
Point-to-Point Transmission Service is available for a period of 1 day 
or longer.
    The formula for the rate is as follows:
    [GRAPHIC] [TIFF OMITTED] TN12JA04.054
    
    Non-Firm Point-to-Point Transmission Service: Non-Firm Point-to-
Point Transmission Service is available for periods ranging from 1 hour 
to 1 month. The rate for Non-Firm Point-to-Point Transmission Service 
may be discounted based on market conditions, but will never be higher 
than the Firm Point-to-Point Transmission Service rate, converted to an 
energy equivalent at 100 percent load factor. The formula for the Non-
Firm Point-to-Point Transmission Service rate is:
[GRAPHIC] [TIFF OMITTED] TN12JA04.055

    Unauthorized Use of Transmission: If a Transmission Customer 
(including the transmission provider for third-party sales) engages in 
unauthorized use of RMR-managed transmission systems, the Transmission 
Customer shall be charged 150 percent of the demand charge for the type 
of service at issue (reserved); e.g., hourly, daily, weekly, or 
monthly, with a maximum monthly demand charge. Unauthorized use is 
defined as unscheduled or untagged use of the transmission system and 
any affiliated ancillary service, exceeding reserved capacity at any 
point of delivery or receipt. Unauthorized use may also include a 
customer's failure to curtail transmission when requested.

Transmission Service Comments

    The following comments were received concerning transmission 
service during the Public Consultation and Comment Period. Western 
paraphrased and combined comments when it did not affect the meaning of 
the comment. Western's response follows each comment.
    Comment: Various pieces of study work have been completed that 
detail large-scale wind development in Western's service areas. This 
work shows that significant regional transmission planning work is 
underway to accommodate large scale wind development in Western's 
service areas. Given its hydro power marketing responsibilities and 
extensive transmission network, Western is in a unique situation to 
address wind integration issues.
    Response: While this comment is outside the scope of the rate 
action, Western notes that it has only three existing interconnection 
requests for 30 MW or greater for wind generation within WACM. Western 
is heavily involved in all regional transmission planning work 
currently underway for any wind development within WACM.
    Comment: OASIS data shows firm transmission service is often fully 
subscribed by incumbent firms. Data from SSG-WI shows many regional 
transmission congestion points in WECC to be physically congested only 
a small portion of the time, yet non-firm transmission service under 
FERC Order No. 888 compliant tariffs is only available for periods of 
less than 1 year. As wind is able to be dispatched off the system, 
investigation of the use of physically available transmission on a 
long-term, non-firm basis might show how wind could make use of 
existing transmission during non-congested times.
    Response: While this comment is outside the scope of the rate 
action, Western notes that FERC Order No. 888 does not provide for the 
offering of Non-Firm Point-to-Point Transmission Service on a long-term 
basis. The sale of non-firm transmission service on a long-term basis 
would complicate the management of scheduling and dispatching and would 
cause a significant increase in the number of transmission 
curtailments. Western will accept requests for non-firm short-term 
transmission. The availability of non-firm short-term transmission is 
posted on Western's OASIS Web site.
    Comment: With regard to generator modeling for stability analysis, 
wind farm and wind technology design options can vary depending on 
circumstances. Engineering interconnection software should have the 
correct wind options in data libraries. An iterative process between 
wind project developers and grid operators is needed to determine good 
utility practices for interconnecting wind resources.
    Response: While this comment is outside the scope of the rate 
action, Western is committed to engaging with interested parties in 
order to determine the best utility practices for the interconnection 
of wind resources into WACM.
    Comment: With regard to cost allocations for transmission upgrades 
and additions, the allocations for upgrades and additions must take 
into account both costs imposed by new generators and the system 
benefits of investments.
    Response: Cost allocations for transmission upgrades will be 
addressed on a case-by-case basis. While the allocation of integration 
costs themselves is fairly straightforward, the determination of 
benefits to the system is more complex and will be determined through 
the use of power flow studies

[[Page 1730]]

using modeling techniques or other tools available.
    Comment: Various commenters interested in the impact of Western's 
actions on wind generation stand ready to engage with Western in 
constructive dialogue toward resolution of the issues that Western and 
wind developers face as large-scale wind development spreads in 
Western's service territory. They propose an initial workshop co-
sponsored by Western, the National Renewable Energy Laboratory, the Oak 
Ridge National Laboratory, and others. The agenda should allow 
participants to share data and methods developed elsewhere, to discuss 
preliminary findings already in hand, and to develop the issues and 
agendas for working groups to resolve the issues in this rate 
proceeding and begin the process of addressing the broader issues 
raised in these comments.
    Response: Western continues its ongoing dialogue with wind 
generation proponents. As stated in this rate order, in response to 
feedback received during the public process, Western has delayed 
implementation of the Regulation service capacity-based charge for 
intermittent renewable resources. Western plans to reopen the rate for 
Regulation service in its entirety early in 2004 and begin a separate 
public process.
    Comment: A customer comments that it is supportive of changes being 
proposed for lower transmission rates. Lower rates encourage additional 
use of the transmission system, which lowers native transmission 
customers' revenue requirements.
    Response: Western appreciates the comment. However, while the 
annual rate may fluctuate based on financial and load data updates, the 
rate methodology has not changed.

Ancillary Services Discussion

    Seven 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 five ancillary services--Regulation, Energy 
Imbalance Service, Spinning Reserves, Supplemental Reserves, and 
Transmission Losses Service--will also be offered, but customers have 
the option of self-supplying or purchasing them from another entity. 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.
    The formula rates for ancillary services are based on WACM's costs 
and are designed to recover only the costs associated with providing 
the service(s). WACM Federal power resources consist of all the LAP 
Federal power resources and a portion of the CRSP Federal power 
resources.
    Scheduling, System Control, and Dispatch Service: The cost for 
providing Scheduling, System Control, and Dispatch Service for 
Transmission Customers is included in the appropriate transmission 
service rates. This service can be provided only by the operator of the 
control area in which the transmission facilities are located. The 
formula rates will be applied to all tags for WACM non-Federal 
transmission customers.
    The formula rate for Scheduling, System Control, and Dispatch is 
based on the annual cost of all personnel and related costs involved in 
providing the service for WACM. The annual cost is divided by the 
number of electronic tags per year to derive a ``rate per tag'' to be 
applied per day. The electronic tag represents a specific request for 
transmission of energy through, within, into, or out of, WACM, per day.
    While the revenue requirement calculation is consistent with the 
1998 rate order submittal, the charge basis is changing from ``per 
schedule per day'' to ``per tag per day.''
    The charge will be assessed to the last transmission provider 
displayed in the electronic tag, unless other arrangements are made 
with WACM.
    RMR will accept any number of tag changes over the course of a day, 
without additional charge, so that entities trying to follow their 
loads closely may do so without penalty.
    Based on FY 2002 data, the rate for Scheduling, System Control, and 
Dispatch Service for WACM will be $25.22 per tag per day, effective 
March 1, 2004.
    Reactive Supply and Voltage Control Service from Generation 
Sources: The formula rate for VAR Support is based upon Reclamation's 
net generation plant investment in WACM. Annual Fixed Charge Rates 
based on annual generation-related O&M, A&GE, depreciation, and 
interest expenses for LAP and CRSP 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 CRSP, and those results are 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 2002 data, the WACM rate for VAR 
Support is $0.106/kW-month.
    Full or partial credit may be given to those customers with 
generators providing WACM with VAR Support. Any crediting arrangement 
must be documented in the customers' Service Agreements.
    Regulation and Frequency Response Service: The rate for Regulation 
is a load-based rate, and will be applied against customer's loads 
within WACM.
    The formula rate for Regulation is based upon a current analysis 
that shows WACM presently requires approximately 75 MW of regulating 
capacity to meet the control area needs. The amount of regulation and 
cost of associated purchases will be revised annually to accurately 
reflect the capacity needed to supplement hydroelectric resources.
    The revenue requirement for that regulating capacity is comprised 
of: (1) The annualized cost of LAP regulating plants in WACM; (2) the 
revenue requirement for CRSP regulating plants within WACM; and (3) the 
cost of a capacity purchase to support regulation. Net investment costs 
for only those plants that are able to provide regulating service were 
included in (1) and (2), above.
    For LAP, the same Annual Fixed Charge Rate used in the VAR Support 
formula was used to convert the LAP net plant investment to an annual 
cost for Regulation. The annual cost was divided by the nameplate 
capacity of the applicable plants to yield an average cost per kilowatt 
for LAP. LAP's revenue requirement for the provision of 25 MW is 
$1,189,750.
    For CRSP, the revenue requirement was provided to RMR from the CRSP 
Management Center in Salt Lake City using the same methodology, but 
with CRSP's net investment and Annual Fixed Charge Rate. Historical 
operational experience shows that the amount of regulating capacity 
provided for CRSP loads is 40 MW. With the division of CRSP's load into 
two control areas on April 1, 1998, WACM received one-half of the 40 MW 
of capacity, or 20 MW. CRSP's valuation of the revenue requirement for 
WACM's 20 MW is $480,185.
    Additionally, a 30 MW purchase of capacity was made at a net cost 
of $3,416,400.
    The total of these three components to provide WACM with 75 MW of 
regulating capacity is $5,086,335. The load in WACM requiring 
regulation is 2,425,221 kW (12-cp value).

[[Page 1731]]

    Based upon FY 2002 data, the rate for Regulation effective March 1, 
2004, will be $0.175/kW-month.
    Customers who provide WACM with Regulation will receive a credit. 
These types of crediting arrangements must be documented in 
Transmission Customers' Service Agreements.
    Energy Imbalance Service: The Commission established guidelines in 
FERC Order No. 888 for Energy Imbalance Service of +/-1.5 percent 
hourly deviation (3 percent bandwidth) with a 2 MW minimum deviation, 
as in its view, anything more or less than that could affect system 
reliability. However, RMR recognizes that metering inadequacies, 
changes in scheduling practices, and unit control problems may hinder 
customers' ability to meet the 3 percent bandwidth. Therefore, RMR has 
established a +/-5-percent hourly deviation (10 percent bandwidth) with 
a 4 MW minimum deviation. Energy Imbalance Service taken within the 
bandwidth will be charged or credited 100 percent of the LAP weighted 
hourly average real-time purchase or sale price that hour. Energy 
Imbalance Service taken outside the bandwidth will be charged a 25 
percent penalty.
    In the previously approved rate schedule for this service, the 
minimum deviation was 2 MW and the penalty for excursions outside the 
bandwidth was 50 percent.
    In this rate order, the 2 MW minimum is increased to a 4 MW minimum 
to afford smaller customers increased operating flexibility. Western 
decreased the out-of-bandwidth penalty from 50 percent to 25 percent 
after conducting an analysis of imbalances since implementation (July 
2002). The out-of-bandwidth excursions did not appear to significantly 
impact Western's operations; therefore, Western decreased the penalty.
    All Energy Imbalance Service provided by WACM, both inside and 
outside the bandwidth, will be settled financially and accounted for 
hourly after the fact. The +/-5 percent will be applied against a 
customer's actual load, and will be calculated hourly to any energy 
imbalance that occurs as a result of a customer's schedules and/or 
meter data.
    There are normally four scenarios for Energy Imbalance Service, 
each of which receives a specific pricing calculation. These scenarios 
are: (1) Over delivery within the bandwidth; (2) under delivery within 
the bandwidth; (3) over delivery outside the bandwidth; and (4) under 
delivery outside the bandwidth. The respective pricing for each 
scenario is: for (1) and (2) 100 percent of LAP weighted hourly average 
real-time sale or purchase price would apply, dependent upon the 
control area energy condition in aggregate; for (3) 75 percent of LAP 
weighted hourly average real-time sale price would apply; and for (4) 
125 percent of the LAP weighted hourly average real-time purchase price 
would apply.
    When there are no real-time sales or purchases within an hour, the 
pricing defaults both within and outside the bandwidth will be applied 
in the following order:
    1. Weighted hourly average real-time sale or purchase pricing for 
the day (on and off peak).
    2. Weighted hourly average real-time sale or purchase pricing for 
the current month (on and off peak).
    3. Weighted hourly average real-time sale or purchase pricing for 
the prior month.
    4. Weighted hourly average real-time sale or purchase pricing for 
the month immediately prior to the prior month (and continuing in this 
manner until sale or purchase pricing is located) for on and off peak.
    Western supports the development of intermittent renewable energy 
sources, but does not have the resource capability to cover 
fluctuations anticipated with such resources. However, Western is 
willing to purchase, on a pass-through cost basis, the requirements to 
mitigate the fluctuations inherent in intermittent resources. No 
bandwidth will apply. This will assure that intermittent resource 
providers pay only for the Energy Imbalance Service they take. They 
will not be penalized for any out-of-bandwidth activity.
    For jointly-owned generators and any other generators within the 
control area without designated load, the bandwidth established for 
Energy Imbalance Service will be +/-2 percent of the actual hourly 
generation output of the units at issue. The charges or credits for 
Energy Imbalance Service will be assigned to the operating agent of the 
generator, unless WACM is provided with a copy of a signed agreement 
from all of the generation owners designating a specific methodology to 
allocate among owners and entitlees. Western reserves the right to 
refuse a designation that does not provide for the full and accurate 
recovery of all generator energy imbalances existing among owners and/
or entitlees. The generation owners will be responsible for proper 
tagging and scheduling of the generation to ensure the accurate 
assignment of Energy Imbalance Service.
    Bandwidth expansion will be made for physical resource loss, 
contribution to the control area for frequency reserves requirements, 
and for the transition of large generating resources.
    During periods of control area operating constraints, Western 
reserves the right to eliminate credits for over deliveries. 
Additionally, parties who over or under deliver may share in potential 
penalty costs assessed against Western for operation outside of 
established utility guidelines.
    Operating Reserves--Spinning and Supplemental: WACM has no long-
term reserves available beyond its own internal requirements, based on 
the post-1999 Resource Study done in July 1995.
    At a customer's request, an offer will be made to purchase reserves 
and pass through that cost, plus an amount for administration. 
Additionally, the customer would be responsible for providing the 
transmission to deliver these reserves.
    Transmission Losses Service: Transmission losses will be assessed 
for all real-time and prescheduled transactions on transmission 
facilities managed by Western or within WACM. Transmission Customers 
will be allowed the option of energy repayment either concurrently or 7 
days later, using the same profile. Transmission Customers must declare 
their preference annually, as to which method of energy payback they 
prefer. When a transmission loss energy obligation is not provided (or 
under provided) by a Transmission Customer for a transmission 
transaction, the cost of energy still owed for losses will be 
calculated based upon the LAP weighted average hourly real-time 
purchase price. Pricing for loss energy due 7 days later, and not 
received by WACM, will be priced at the 7-day-later price (the LAP 
weighted average hourly real-time purchase price with the same defaults 
as Energy Imbalance Service). There will be no financial compensation 
or energy returned to Transmission Customers for over delivery of 
transmission losses, as there should be no condition beyond the control 
of the Transmission Customer that results in overpayment.
    There will be no administrative charge for Transmission Losses 
Service.

Ancillary Service Comments

    RMR received written comments concerning the ancillary services 
during the Public Consultation and Comment Period. These comments have 
been paraphrased where appropriate, without compromising the meaning of 
the comments. Certain comments were duplicative in nature, and were

[[Page 1732]]

combined. RMR's response follows each comment.
    Comment: Large-scale wind development is on the horizon, including 
very large wind resources in all of Western's states. Western should be 
taking a leadership role in addressing wind integration issues.
    Response: Western is committed to working with all interested 
parties to ensure that wind development in Western's control areas is 
supported in a fair and equitable manner. As mentioned earlier in this 
rate order, Western plans to engage in a dialogue with the public 
concerning a Regulation rate design for intermittent renewable 
resources in early 2004, after which time Western will reopen the 
Regulation rate for another separate public process to continue through 
the spring and summer of 2004.
    Comment: A commenter states that requirements to schedule 
generation a day or more ahead of delivery, challenges the development 
of wind resources in the absence of agreement on wind forecasting 
methods and implementation, and can unnecessarily raise ancillary 
service costs for wind.
    Response: Western requires the preschedule of generation in 
adherence to NERC and WECC policies regarding deadlines for submittal 
of tags for energy and transmission schedules. However, NERC Policy 3 
allows changes to schedules up to 20 minutes prior to the hour in an 
hourly scheduling environment. Western, therefore, believes that 
considerable scheduling flexibility is available for balancing 
resources and loads.
    Comment: Many comments were received concerning the proposed rate 
for Regulation and Frequency Response Service for Intermittent 
Renewable Resources. These comments included concerns about rate 
design, implementation, and undue financial penalties and/or charges 
for intermittent renewable resources.
    Response: As indicated earlier in this rate order, due to the large 
number of comments received concerning this component of the Regulation 
rate, Western has withdrawn the capacity-based rate component from the 
Rate Schedule for Regulation and Frequency Response Service to be 
implemented March 1, 2004. Western will further study the issue and 
early in 2004 will engage in an informal process with the public 
concerning the Regulation rate and its design. After receiving informal 
public input, Western will reopen the Regulation rate for a formal 
public process.
    Comment: A commenter believes that Western should charge an 
administrative fee for Energy Imbalance Service, similar to the way 
CRSP assesses administrative charges for its Western Replacement Power 
and/or Customer Displacement Power products.
    Response: Western has reviewed this issue and determined that it 
will not assess an administrative charge for Energy Imbalance Service. 
Western views Energy Imbalance Service as an integral function and 
responsibility of the WACM control area, recoverable under O&M.
    Comment: With regard to Energy Imbalance Service for jointly owned 
generators, a commenter suggests that Western use 2 percent of the unit 
rating, instead of the current policy of using 2 percent of the actual 
generation output, as the bandwidth margin.
    Response: Western will continue to use 2 percent of the actual 
generation output as the bandwidth margin for Energy Imbalance Service. 
Western believes that this is more reasonable than applying 2 percent 
to the unit's rating.
    As an example, if a 400 MW plant has an actual output in an hour of 
only 50 MW, the use of the unit's 400 MW nameplate capacity results in 
a bandwidth of 8 MW for a 50 MW output, or a 16 percent bandwidth. When 
the 2 percent is applied in this same example to the 50 MW of actual 
generation output, the result is a bandwidth of +/-1 MW.
    Comment: A commenter suggests opening the bandwidth for Energy 
Imbalance Service to forgive shortfalls of large coal units' 
generation, if the shortfall is caused by station service associated 
with a large coal unit being off line.
    Response: Station service loads are the responsibility of the plant 
owner's LSE. These loads are covered for up to the initial 2 hours of 
an unplanned outage under membership in the Rocky Mountain Reserve 
Sharing Group. It is the LSE's responsibility to schedule for these 
loads after this initial period. Therefore, Western will not open the 
bandwidth for imbalances resulting from the incorrect scheduling of 
station service loads.
    Comment: A commenter suggests that Western expand the minimum 
deviation for Energy Imbalance Service from 2 MW to 4 MW.
    Response: Western agrees with the commenter and is expanding the 
minimum deviation for Energy Imbalance Service from 2 MW to 4 MW, to 
provide smaller customers greater flexibility in balancing their loads 
and resources.
    Comment: Western should clarify what it means by ``eliminating the 
bandwidth for intermittent renewables' imbalances'' for Energy 
Imbalance Service. Does this mean that there will be zero deviation 
from schedules allowed or that infinite deviation will be allowed?
    Response: For Energy Imbalance Service calculated for intermittent 
renewable resources within WACM, Western will apply no bandwidth. What 
this means is that hour-to-hour, the intermittent renewable resource 
will pay 100 percent or receive 100 percent of the LAP weighted average 
hourly purchase or sale price, respectively. No penalty will apply to 
Energy Imbalance Service taken by an intermittent renewable resource.
    Comment: A commenter asks for a credit for the self-provision of 
Regulation service.
    Response: Western notes that there is a crediting provision in the 
existing rate for Regulation service for entities that are able to 
self-provide this service or are purchasing it from another party. This 
eligibility for a credit is also contained in the rate schedule for 
Regulation that is part of this rate order. Any such crediting 
arrangement will need to be documented in the entity's Service 
Agreement.
    Comment: A commenter notes that Western will charge ``market'' 
rates for imbalances. The commenter has a concern that Western should 
never be allowed to over collect revenues by forcing wind generators 
into the currently imperfect imbalance market, and keeping the spread 
whenever imbalances partly or completely cancel each other out.
    Response: The rates that Western charges for Energy Imbalance 
Service are the LAP weighted average hourly real-time purchase and 
sales prices; that is, they are Western's actual costs and revenues for 
power. As such, Western is neither making a profit on energy over 
delivered for Energy Imbalance Service, nor is it suffering a loss on 
energy under delivered for Energy Imbalance Service. Western, acting as 
the WACM control area operator, merely balances out the loads and 
resources, by either selling or purchasing energy, and passing the 
costs on to customers as appropriate for their specific energy 
condition.
    Comment: A commenter would like a full description about how the 
Energy Imbalance Service financial settlement will work. Western should 
allow netting imbalances for intermittent renewables over a monthly 
billing period to simplify the administration and financial impact of 
imbalance payments.

[[Page 1733]]

    Response: Western's Energy Imbalance Service accounting is 
accomplished based upon a financial settlement methodology, performed 
hourly, 3 to 4 months after the fact. Each hour's imbalance is 
calculated using LAP weighted average hourly real-time purchase or 
sales pricing. Due to hourly variations in the value of energy, Western 
will not allow the netting of energy over the course of a month. This 
could result in a financial loss or gain for the control area, and 
Western's methodology is based on cost-recovery for over or under 
deliveries.
    Comment: A commenter states that arbitrary, non-cost based 
penalties for not meeting schedules by intermittent generators (who do 
not have the ability to ``game'' the system) in the absence of market-
based real-time settlements for Energy Imbalance Service, can and 
should be eliminated for wind without negatively impacting grid 
operations or costs.
    Response: Western uses market-based real-time settlements for 
Energy Imbalance Service financial calculations. This allows customers 
with energy imbalances to be charged or credited for only the identical 
purchase or sale that WACM had to make in order to balance the control 
area. It is not Western's intent to make a profit with Energy Imbalance 
Service, but only to recover actual costs from appropriate parties. 
Western reiterates that there will be no penalties associated with 
Energy Imbalance Service caused by intermittent renewable resources.
    Comment: A commenter is very concerned about the proposal to round 
hourly Energy Imbalance Service to the nearest whole MW. Western has 
said the effect is negligible, but it will mean a cost increase to the 
commenter of 270 percent. This is a significantly negative impact to 
the commenter. The commenter would like to know the apparent, 
compelling reason to change the methodology.
    Response: Western had originally proposed rounding Energy Imbalance 
Service up to the nearest whole MW hourly, predicated upon a concern 
from a customer regarding the inability to have zero energy imbalance 
in an hour due to the scheduling of energy in MWs and the actual meter 
readings in kWs.
    Upon further study, Western has determined that the rounding of 
Energy Imbalance Service hourly values can be beneficial in some hours, 
but detrimental in others.
    In this final rate order, the hourly Energy Imbalance Service 
values and subsequent billing will remain in kWs. When the customer 
over delivers kWs, it is credited for those kWs in that hour; when the 
customer under delivers kWs, it is charged for those kWs in that hour.

Regulatory Flexibility Analysis

    Under 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 rates are of 
limited applicability, no flexibility analysis is required.

Small Business Regulatory Enforcement Fairness Act

    Western has determined that this rule is exempt from congressional 
notification requirements under 5 U.S.C. 801 because the action is a 
rulemaking of particular applicability relating to rates or services 
and involves matters of procedure.

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 1500-1508); and DOE NEPA Regulations (10 CFR 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 the Commission 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 March 1, 2004, formula rates for 
transmission and ancillary services under Rate Schedules L-NT1, L-FPT1, 
L-NFPT1, L-AS1, L-AS2, L-AS3, L-AS4, L-AS5, L-AS6, and L-AS7. The rate 
schedules shall remain in effect on an interim basis, pending the 
Commission's confirmation and approval of them or substitute formula 
rates on a final basis through February 28, 2009.

    Dated: December 30, 2003.

Kyle E. McSlarrow,
Deputy Secretary.

Rate Schedule L-AS1, Schedule 1 to Tariff, March 1, 2004; Rocky 
Mountain Region, Loveland Area Projects 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 rate will be applied to all electronic tags for WACM non-
transmission customers. The Rocky Mountain Region (RMR) will accept any 
number of tagging 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 will be listed in a revision to this rate schedule 
issued under applicable Federal laws, regulations, and policies and 
made part of the applicable service agreement.
    RMR will charge the non-transmission customer the rate then in 
effect. The charge will be assessed to the last transmission provider 
displayed in the electronic tag, unless other arrangements are made 
with WACM.

Effective

    The first day of the first full billing period beginning on or 
after March 1, 2004, through February 28, 2009.

Formula Rate

[[Page 1734]]

[GRAPHIC] [TIFF OMITTED] TN12JA04.056

Rate

    The rate to be in effect March 1, 2004, through September 30, 2004, 
is $25.22 per tag per day. This rate is based on the above formula and 
on FY 2002 data.

Rate Schedule L-AS2, Schedule 2 to Tariff, March 1, 2004; Reactive 
Supply and Voltage Control From Generation Sources Service

Applicable

    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 supplied to the Customer's (Loveland Area Projects (LAP) 
Transmission Customers and customers on others' transmission systems 
within the WACM) transactions will be 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 outlined below.
    The LAP charges for VAR Support may be modified upon written notice 
to the Customer. Any change to the charges for VAR Support will be 
listed in a revision to this rate schedule issued under applicable 
Federal laws, regulations, and policies and made part of the applicable 
service agreement. The Rocky Mountain Region will charge the Customer 
under the rate then in effect.
    Credit may be given to those Customers with generators providing 
WACM with VAR Support. Any crediting arrangements must be documented in 
the Customer's Service Agreement.

Unauthorized Use of Control Area Services

    If a Customer (including the transmission provider for third-party 
sales) engages in unauthorized use of RMR-managed transmission systems, 
the Customer shall be charged 150 percent of the demand charge for the 
type of service at issue (reserved); e.g., hourly, daily, weekly, or 
monthly, with a maximum demand charge set at monthly.
    Unauthorized use is defined as unscheduled or untagged use of the 
transmission system and any affiliated ancillary service, exceeding 
reserved capacity at any point of delivery or receipt. Unauthorized use 
may also include a Customer's failure to curtail transmission when 
requested.

Effective

    The first day of the first full billing period beginning on or 
after March 1, 2004, through February 28, 2009.

Formula Rate

Total Annual Revenue Requirement for Generation = TARRG
Percentage of Resource Capacity Used for VAR Support = % of Resource
[GRAPHIC] [TIFF OMITTED] TN12JA04.057

Rate

    The rate to be in effect March 1, 2004, through September 30, 2004, 
is:

Monthly: $0.106/kW-month
Weekly: $0.024/kW-week
Daily: $0.003/kW-day
Hourly: $0.000125/kWh

    This rate is based on the above formula and on FY 2002 financial 
and load data.

Rate Schedule L-AS3, Schedule 3 to Tariff, March 1, 2004; 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 Customers (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 their Regulation obligations. The charges for 
Regulation are outlined below.
    The LAP charges for Regulation may be modified upon written notice 
to the Customer. Any change to the Regulation charges will be listed in 
a revision to this rate schedule issued under applicable Federal laws, 
regulations, and policies and made part of the applicable service 
agreement. The Rocky Mountain Region (RMR) will charge the Customer 
under the rate then in effect.
    Credit will 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 March 1, 2004, through February 28, 2009.

Formula Rate
[GRAPHIC] [TIFF OMITTED] TN12JA04.058


[[Page 1735]]



Rate

    The rate to be in effect March 1, 2004, through September 30, 2004, 
is:

Monthly: $0.175/kW-month
Weekly: $0.040/kW-week
Daily: $0.006/kW-day
Hourly: $0.000250/kWh

    This rate is based on the above formula and on FY 2002 financial 
and load data.

Rate Schedule L-AS4, SCHEDULE 4 to Tariff, March 1, 2004; Energy 
Imbalance Service

Applicable:

    This rate applies to all customers receiving Energy Imbalance 
Service from the Rocky Mountain Customer Service Region's Western Area 
Colorado Missouri control area (WACM).
    WACM provides Energy Imbalance Service when there is a difference 
between a Customer's (Loveland Area Projects Transmission Customers and 
customers on others' transmission systems within WACM) resources and 
obligations. Energy Imbalance is calculated as resources minus 
obligations (adjusted for transmission and transformer losses) for any 
combination of scheduled transfers, transactions, or actual load 
integrated over each hour. Customers within WACM must either obtain 
this service from WACM or make alternative comparable arrangements to 
satisfy their Energy Imbalance Service obligation.

Effective

    The first day of the first full billing period beginning on or 
after March 1, 2004, through February 28, 2009.

Formula Rate

    All Energy Imbalance Service provided, both inside and outside the 
bandwidth, will be settled financially, accounted for hourly at the end 
of each month. WACM will establish a deviation band of +/- 5 percent 
(with a minimum of 4 MW) of the actual load to be applied hourly to any 
energy imbalance that occurs as a result of a Customer's schedules and/
or meter data.
    Normally, there are four scenarios for Energy Imbalance Service. 
They are: (1) over delivery within the bandwidth; (2) under delivery 
within the bandwidth; (3) over delivery outside the bandwidth; and (4) 
under delivery outside the bandwidth. During periods of control area 
operating constraints, Western reserves the right to eliminate credits 
for over deliveries and parties over or under delivering may share in 
the cost to Western of any penalty.

Within the Bandwidth

    The gross energy imbalance for each applicable entity within WACM 
shall be totaled and netted to determine an aggregate energy imbalance 
for WACM. The sign of the aggregate energy imbalance will determine 
whether sale or purchase pricing will be used (surplus conditions use 
sale pricing and deficit conditions use purchase pricing).
    Depending upon the sign of the aggregate energy imbalance for all 
entities within WACM, the pricing for charges and credits within the 
bandwidth will be: Weighted Average Real-Time Sale or Purchase Price.

Outside the Bandwidth

    Each entity within WACM will be charged or credited independently 
for Energy Imbalance Service taken, depending on its over-or under-
delivery status.
    Under Delivery (customer deficit) = Customer will be charged 125% 
of the weighted average real-time purchase price.
    Over Delivery (customer surplus) = Customer will be credited 75% of 
the weighted average real-time sale price.
    Expansion of the bandwidth will be allowed during the following 
instances:

--The loss of a physical resource.
--Upon evidence of proven frequency bias contribution for control area 
needs.
--The transition (start up/shut down) period for large generating 
resources.

Jointly-Owned Generation or Generation Without Designated Load

    For jointly-owned generators and any other generators within the 
control area without designated load, the bandwidth established for 
Energy Imbalance Service will be +/-2 percent of the actual hourly 
generation output of the units at issue. The charges or credits for 
Energy Imbalance Service will be assigned to the operating agent of the 
generator, unless WACM is provided with a copy of a signed agreement 
from all of the owners designating a specific methodology to allocate 
among owners and entitlees. Western reserves the right to refuse a 
designation that does not provide for the full and accurate recovery of 
all generator energy imbalances existing among owners and/or entitlees. 
The generator owners will be responsible for proper tagging and 
scheduling of the generation to ensure that the Energy Imbalance 
Service is assigned accurately.

Pricing Defaults

    When no hourly data is available, the pricing defaults for sales 
and purchase pricing both within and outside the bandwidth will be 
applied in the following order:
    1. Weighted average real-time sale or purchase pricing for the day 
(on and off peak).
    2. Weighted average real-time sale or purchase pricing for the 
month (on and off peak).
    3. Weighted average real-time sale or purchase pricing for the 
prior month.
    4. Weighted average real-time sale or purchase pricing for the 
month prior to the prior month (and continuing until sale or purchase 
pricing is located) (on and off peak).

Rate

    This bandwidth applicable to load is in effect March 1, 2004, 
through February 28, 2009, and is +/-5 percent of hourly actual load, 
with a 4 MW minimum deviation.
    The bandwidth applicable to jointly owned generators or generators 
without designated load is in effect March 1, 2004, through February 
28, 2009, and is +/-2 percent of hourly actual generation, with a 4 MW 
minimum deviation.
    The pricing and penalty for deviations inside and outside the 
bandwidth is described above.

Rate Schedule L-AS5, Schedule 5 to Tariff, March 1, 2004; 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 Customers (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 their Reserve obligations. The charges for Reserves are shown 
below. The amount of Reserves will be outlined in the service 
agreement.

Effective

    The first day of the first full billing period beginning on or 
after March 1, 2004, through February 28, 2009.

Formula Rate

    No long-term Reserves are available beyond internal WACM 
requirements.
    At a Customer's request, Western may purchase Reserves and pass 
through that cost, plus an amount for administration. Additionally, the 
Customer would be

[[Page 1736]]

responsible for providing the transmission to deliver the Reserves.

Rate Schedule L-AS6, Schedule 6 to Tariff, March 1, 2004; 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 
Customers (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 their Reserve 
obligations. The charges for Reserves are outlined below. The amount of 
Reserves will be listed in the service agreement.

Effective

    The first day of the first full billing period beginning on or 
after March 1, 2004, through February 28, 2009.

Formula Rate

    No long-term Reserves are available beyond internal WACM 
requirements.
    At a Customer's request, Western may purchase Reserves and pass 
through that cost, plus an amount for administration. Additionally, the 
Customer would be responsible for providing the transmission to deliver 
the Reserves.

Rate Schedule L-AS7, Schedule 9 to Tariff, March 1, 2004; Transmission 
Losses Service

Applicable

    This rate schedule covers providing transmission losses for 
transactions within WACM as posted on the Rocky Mountain Region OASIS 
Web site.

Effective

    The first day of the first full billing period beginning on or 
after March 1, 2004, through February 28, 2009.

Formula Rate

    Transmission losses will be assessed for all real-time and 
prescheduled transactions on transmission facilities managed by 
Western-RMR or within WACM. Transmission Customers will be allowed the 
option of energy repayment either concurrently or 7 days later, same 
profile. Transmission Customers must declare their preference annually, 
as to which method of energy payback they wish to use.
    However, when a transmission loss energy obligation is not provided 
(or is under provided) by a Transmission Customer for a transmission 
transaction, the energy still owed for losses will be calculated and a 
charge will be assessed to the Transmission Customer, based on the LAP 
weighted average hourly real-time purchase price.
    Pricing for loss energy due 7 days later, and not received by WACM, 
will be priced at the 7 day later-price (the LAP weighted average 
hourly real-time purchase price with same defaults as Energy Imbalance 
Service).
    There will be no financial compensation or energy return to 
Transmission Customers for over delivery of transmission losses, as 
there should be no condition beyond the control of the Transmission 
Customer that results in overpayment.

Rate

    This rate is in effect March 1, 2004, through February 28, 2009. 
Transmission Customers may settle financially or with energy. The 
pricing for this service will be the LAP weighted average hourly real-
time purchase price with the same defaults as Energy Imbalance Service.

Rate Schedule L-FPT1, Schedule 7 to Tariff, March 1, 2004; Long-Term 
Firm and Short-Term Firm Point-to-Point Transmission Service

Applicable

    The Transmission Customer shall compensate the Rocky Mountain 
Region (RMR) each month for Reserved Capacity under the applicable Firm 
Point-to-Point Transmission Service Agreement and rates outlined below. 
The formula rates used to calculate the charges for service under this 
schedule were issued and may be modified under 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 will be listed in a revision to this rate schedule 
and made part of the applicable service agreement. RMR shall charge the 
Transmission Customer under 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.

Unauthorized Use of Transmission

    If a Transmission Customer (including the transmission provider for 
third-party sales) engages in unauthorized use of RMR-managed 
transmission systems, the Transmission Customer shall be charged 150 
percent of the demand charge for the type of service at issue 
(reserved); e.g., hourly, daily, weekly, or monthly, with a maximum 
demand charge set at monthly.
    Unauthorized use is defined as unscheduled or untagged use of the 
transmission system and any affiliated ancillary service, exceeding 
reserved capacity at any point of delivery or receipt. Unauthorized use 
may also include a Transmission Customer's failure to curtail 
transmission when requested.

Formula Rate
[GRAPHIC] [TIFF OMITTED] TN12JA04.059


[[Page 1737]]


    If a Transmission Customer requires use of subtransmission 
facilities, a specific facility use charge will be assessed in addition 
to this formula rate.

Effective

    The first day of the first full billing period beginning on or 
after March 1, 2004, through February 28, 2009.

Rate

    The rate to be in effect March 1, 2004, through September 30, 2004, 
is as follows:
    Maximum of:

Yearly: $32.13/kW of reserved capacity per year
Monthly: $2.68/kW of reserved capacity per month
Weekly: $0.62/kW of reserved capacity per week
Daily: $0.09/kW of reserved capacity per day

    This rate is based on the above formula and FY 2002 data.

Rate Schedule L-NFPT1, Schedule 8 to Tariff, March 1, 2004; Non-Firm 
Point-to-Point Transmission Service

Applicable

    The Transmission Customers will compensate Rocky Mountain Region 
(RMR) for Non-Firm Point-to-Point Transmission Service under the 
applicable Non-Firm Point-to-Point Transmission Service Agreement and 
rate outlined below. The formula rates used to calculate charges for 
service under this schedule were issued and may be modified under 
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 will be listed in a revision to this rate schedule 
and made part of the applicable service agreement. RMR will charge the 
Transmission Customer under the rate then in effect.

Discounts

    Three principal requirements apply to discounts for transmission 
service: (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.

Unauthorized Use of Transmission

    If a Transmission Customer (including the transmission provider for 
third-party sales) engages in unauthorized use of RMR-managed 
transmission systems, the Transmission Customer will be charged 150 
percent of the demand charge for the type of service at issue 
(reserved); e.g., hourly, daily, weekly, or monthly, with a maximum 
demand charge set at monthly.
    Unauthorized use is defined as unscheduled or untagged use of the 
transmission system and any affiliated ancillary service, exceeding 
reserved capacity at any point of delivery or receipt. Unauthorized use 
may also include a Transmission Customer's failure to curtail 
transmission when requested.

Effective

    The first day of the first full billing period beginning on or 
after March 1, 2004, through February 28, 2009.

Formula Rate
[GRAPHIC] [TIFF OMITTED] TN12JA04.060

Rate

    The rate to be in effect March 1, 2004, through September 30, 2004, 
is:
    Maximum of:

Monthly: $2.68/kW of reserved capacity per month
Weekly: $0.62/kW of reserved capacity per week
Daily: $0.09/kW of reserved capacity per day
Hourly: 3.75 mills/kWh

    This rate is based on the above formula and FY 2002 data.

Rate Schedule L-NT1, Attachment H to Tariff, March 1, 2004; Annual 
Transmission Revenue Requirement for Network Integration Transmission 
Service

Applicable

    Transmission Customers will compensate the Rocky Mountain Region 
(RMR) each month for Network Transmission Service under 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 schedule was 
issued and may be modified under 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 will be listed in a revision to this rate schedule 
and made part of the applicable service agreement. RMR will 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 March 1, 2004, through February 28, 2009.

Formula Rate
[GRAPHIC] [TIFF OMITTED] TN12JA04.061


[[Page 1738]]


    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 March 1, 2004, through September 
30, 2004, is $38,776,237. This revenue requirement is based on FY 2002 
data.

[FR Doc. 04-575 Filed 1-9-04; 8:45 am]
BILLING CODE 6450-01-P