Transmission and Ancillary Services Rates, Pick-Sloan Missouri Basin, Eastern Division

DEPARTMENT OF ENERGY

Western Area Power Administration

Transmission and Ancillary Services Rates, Pick-Sloan Missouri

Basin, Eastern Division

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of proposed rate adjustments.

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SUMMARY: The Western Area Power Administration (Western) is proposing

transmission service and ancillary service rate adjustments for Pick-

Sloan Missouri Basin Program, Eastern Division (P-SMBP-ED). The

proposed formula rates will provide sufficient revenue to repay all

annual costs and assigned investment within the allowable time periods.

The proposed formula rates are scheduled to go into effect May 1, 1998.

This Federal Register notice continues the procedure for public

participation in the transmission and ancillary service rate

adjustments, which began with Western's Advance Announcement dated

March 28, 1997.

DATES: The consultation and comment period for the proposed

transmission service and ancillary service rates will end November 14,

1997. Written comments should be received by Western by the end of the

comment period to be assured consideration. Western will present a

detailed explanation of the proposed rate at the public information

forums which will be held at the following dates and times:

1. October 16, 1997--9 a.m. MDT, Billings, Montana.

2. October 17, 1997--9 a.m. CDT, Sioux Falls, South Dakota.

Western will receive written and oral comments at the public

comment forums which will be held at the following times:

3. November 13, 1997--9 a.m. MST, Billings, Montana.

4. November 14, 1997--9 a.m. CST, Sioux Falls, South Dakota.

ADDRESSES: Western's public information forums will be held at the

following places:

1. Radisson Northern Hotel, Broadway & 1st Avenue North, Billings,

Montana.

2. Howard Johnson, 3300 West Russell Street, Sioux Falls, South

Dakota.

Western's public comment forums will be held at the following

places:

3. Radisson Northern Hotel, Broadway & 1st Avenue North, Billings,

Montana.

4. Howard Johnson, 3300 West Russell Street, Sioux Falls, South

Dakota.

Written comments should be sent to: Gerald C. Wegner, Regional

Manager, Upper Great Plains Region, Western Area Power Administration,

P.O. Box 35800, Billings, MT 59107-5800.

FOR FURTHER INFORMATION CONTACT: Robert F. Riehl, Rates Manager, Upper

Great Plains Region (UGPR), Western Area Power Administration, P.O. Box

35800, Billings, MT 59107-5800, (406) 247-7388. E-mail [email protected]

or visit UGPR's home page at http://www.wapa.gov/ugp/.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Introduction/Background

II. Western's Proposal

III. Proposed Rates

IV. Cost Shifting

V. Other Options

VI. Authorities

I. Introduction/Background

Western initiated a public process to establish long-term open

access transmission and ancillary service rates for the P-SMBP-ED with

its advance announcement of March 28, 1997. Several options were

identified and comments and ideas were solicited on these options.

Forty-five letters were received as a result of the solicitation. The

letters commented on fourteen issues. The most constant and consistent

message received from the comments was that Western should choose a

proposal that would have the least impact upon the P-SMBP-ED firm power

rate. This Federal Register notice continues that process.

II. Western's Proposal

1. Honor Existing Contract Arrangements

Western presently has the following transmission and related

services contract agreements. Western intends to abide by the terms of

these agreements and sustain the benefits incurred from these

agreements.

Basin Electric Power Cooperative (Basin Electric) has a bilateral

Contract, 90-BAO-415, with Western for Joint Transmission System

services. The Contract became effective on the first day of the first

full billing period following the date of its execution, January 5,

1995, and remains in effect

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through the hour ending 2400 of December 31, 2039. Basin Electric also

has a Contract, 90-BAO-431, with Western for transmission service on

the Montana Power Company (MPC) system. The Contract became effective

on the date of its execution, November 6, 1990, and remains in effect

through the hour 2400 on December 31, 2033.

Black Hills Corporation has a bilateral Contract, 88-BAO-320, with

Western for transmission service. The Contract became effective October

1, 1988, and terminates at 12:01 a.m., October 1, 1998, as specified by

the Contract.

Heartland Consumers Power District (Heartland) has a bilateral

Contract, 89-BAO-344, with Western for Joint Transmission System

services. The Contract became effective on the first billing day of the

first full billing period following the date of its execution, December

28, 1995, and remains in effect through the hour ending 2400 on

December 31, 2039.

Minnkota Power Cooperative, Inc. has a bilateral Contract, 88-BAO-

313, with Western for transmission service. The Contract became

effective the first day of the first billing period after the date of

execution, October 6, 1989, and remains in effect through December 31,

2020, as specified in the Contract.

Missouri Basin Municipal Power Agency has a bilateral Contract, 8-

07-60-P0002, with Western for use of the Joint Transmission System. The

Contract became effective on the first day of the November 1977 billing

period and remains in effect until midnight of December 31, 1997, as

defined in the Contract.

Montana-Dakota Utilities Company has a bilateral Contract, 88-BAO-

308, with Western for transmission service. The Contract became

effective on its date of execution, July 1, 1988, and remains in effect

until December 31, 2015.

MPC has a bilateral Contract, 4-07-60-P0228, with Western for

transmission service. The Contract became effective October 15, 1984.

Notice to terminate this Contract has been served and the Contract will

terminate on or about June 30, 1998.

Northwestern Public Service Company has a bilateral Contract, 4-07-

60-P0223, with Western for transmission service. The Contract became

effective on April 1, 1984, and remains in effect until December 31,

2000.

Northern States Power Company has a Contract, 6-07-60-P0236, with

Western for transmission service. The Contract became effective on the

date of its execution, June 2, 1986. Notice to terminate this Contract

has been served and the Contract will terminate on January 31, 2001.

2. The Integrated System Will Be Used for Transmission Service in All

New Electric Service Arrangements

Western, Basin Electric, and Heartland have combined their

transmission facilities to form an Integrated System (IS) and herein

developed transmission and ancillary service rates using a Federal

Energy Regulatory Commission (FERC) approved rate design. Western has

been designated as the operator of the IS by the other participants.

The IS consists of the transmission facilities owned by Basin Electric,

and Heartland east of the east-west electrical separation in the United

States, the transmission facilities owned by Western in the P-SMBP-ED,

and the Miles City DC Tie owned by Western and Basin Electric. These

facilities interconnect with utilities in the States of Montana, North

Dakota, South Dakota, Nebraska, Iowa, Colorado, Minnesota, and Missouri

and in addition include facilities which interconnect with Canada.

Our approach for formation of the IS was to include facilities

which followed the spirit and intent of the order and to make the

system most useful to the transmission requesters. For these reasons we

included several major facilities which were not a part of the Joint

Transmission System. We included the second 345-kV transmission line

between the Antelope Valley and Leland Olds generating stations; which

follows the definitions used for acceptable transmission facilities in

other filings. The 230-kV transmission line between Tioga, North

Dakota, and Boundary Dam, which provides access to loads in Canada, has

been included in the IS. The Miles City DC Tie, which provides for the

transmission of electricity between the east-west electrical separation

of the United States and increases access to transmission on the IS.

The IS also differs from the Joint Transmission System in that it does

not include the transmission facilities owned by the joint owners of

the Laramie River Generating Station, which require the agreement of

all participants prior to inclusion. Basin Electric, and Heartland do

not constitute all the owners in the Laramie River Generating Station.

If they reach agreement, Western, Basin Electric, and Heartland may

consider inclusion of those facilities in the IS rate and tariff.

For each of their new electric service arrangements crossing the IS

facilities, Western, Basin Electric, and Heartland will take service

under the proposed IS rates. To avoid double charging for transmission

services, credit will be given for transmission capacity reservations

in existing Joint Transmission System service contracts for new

transactions from existing resources. Western, as operator of the IS,

will bill for service, collect payments, and distribute revenue to each

participant.

III. Proposed Rates

The proposed rates conform to the spirit and intent of FERC Order

Nos. 888 and 888-A. An Open Access Transmission Tariff (Tariff),

specifying terms and conditions, is being developed under a separate

process. Once implemented, Western, Basin Electric, Heartland, and

others will take service under the proposed Tariff and rates for all

new transmission and/or electric sales arrangements. Western is

requesting public comment on a proposed rate formula that would be

adjusted annually, on or about May 1 of each year, by inserting the

previous year's data into the formula. The data herein is fiscal year

1996 data. These rates will support Western's Tariff and conform with

the spirit and intent of FERC Order Nos. 888 and 888-A. Supporting

information and impacts of these rates are detailed in a rate brochure

available to all interested parties.

1. Proposed Revenue Requirement for IS Transmission Service

The proposed rate for IS transmission service (Network and Point to

Point) is based on a revenue requirement that recovers: (i) The IS

investment and interest cost for Western, Basin Electric, and Heartland

facilities associated with providing IS transmission service; and (ii)

the operation, maintenance, administrative and general cost for

Western, Basin Electric and Heartland allocated to IS transmission

service. This revenue requirement is offset by appropriate transmission

revenues. Rates will be recalculated every year on or about May 1 based

on the previous year's data. The previous year's data to be used in the

recalculation will be made available for review 30 days before the new

rates are implemented. Firm and Non-Firm Point to Point transmission

service rates will be offered on an up-to basis to promote maximum

usage and transmission revenues from the IS.

2. Proposed Rate for Network IS Transmission Service

The proposed rate for monthly Network IS transmission service is

the product of the network customer's load

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ratio share times one-twelfth (\1/12\) of the annual network

transmission revenue requirement. The network transmission revenue

requirement is derived by annualizing the IS transmission investment,

and adding transmission related annual costs, including operation,

maintenance, interest, administrative and general costs. The annual

costs are reduced by revenue credit for the Non-Firm transmission

service. The load ratio share is based on the network customer's hourly

load coincident with the IS monthly transmission system peak minus the

coincident peak for all IS Firm Point-to-Point transmission service

plus the point-to-point reservations. The Network rate includes the

cost for scheduling, system control, and dispatch service needed to

provide transmission service.

3. Proposed Rate for Firm Point-to-Point IS Transmission Service

The proposed Firm Point-to-Point IS rate is based on a revenue

requirement derived by annualizing the IS transmission investment, and

adding transmission related annual costs. These transmission related

annual costs include operation, maintenance, interest, administrative

and general costs. The annual costs are reduced by revenue credits for

Non-Firm transmission. The resultant net annual cost to be recovered is

divided by the capacity reservation needed for the annual average

monthly IS transmission load. Using 1996 data, this methodology

produced a charge of $3.07/kW-month for Firm Point-to-Point

transmission service. This proposed rate may be adjusted each year on

or about May 1, by a recalculation based on the previous years data

using the formula: (Total Annual Revenue Requirement--Non Firm Revenue

Credits)/Annual Average Transmission System Monthly Peak Load/12

months. The point-to-point rate includes the cost for scheduling,

system control, and dispatch service needed to provide transmission

service.

4. Proposed Rate for Non-Firm Point-to-Point Service

The proposed rate for Non-Firm Point-to-Point IS transmission

service is an energy rate up-to but never higher than the Firm Point-

to-Point rate. This rate will remain in effect concurrently with the

Firm Point-to-Point rate. The Non-Firm Point-to-Point rate includes the

cost for scheduling, system control, and dispatch service needed to

provide transmission service.

5. Proposed Rates for Ancillary Services

Western will provide ancillary services, subject to availability,

as described below and as listed in Table 1. The rates are designed to

recover only the costs incurred for providing the service(s).

6. Proposed Rate for Scheduling, System Control and Dispatch Service

Western's annualized costs for scheduling, system control and

dispatch service is determined by multiplying the portion of the

Watertown Operations Office net plant and communications facilities net

plant associated with scheduling, system control and dispatch service

by the transmission fixed charge rate. The annual cost for scheduling,

system control and dispatch service is then divided by the number of

daily schedules in FY 1996. Using 1996 data, this methodology for

determining the scheduling, system control and dispatch service rate

has produced a charge of $54.50/schedule/day. This rate and rate design

is recovering only Western's revenue requirement.

7. Proposed Rate for Reactive Supply and Voltage Control Service

Western's annualized cost for reactive supply and voltage control

is determined by multiplying the total P-SMBP-ED generation net plant

by the generation fixed charge rate. The annualized cost is multiplied

by the capability used for reactive support to determine Western's

reactive service revenue requirement. Basin Electric's and Heartland's

annual revenue requirements are based upon the annualized cost of

equipment installed on their generators to provide this service.

Western's, Basin Electric's, and Heartland's revenue requirements are

summed for the total revenue requirement. The reactive supply and

voltage control service charge is then derived by dividing the revenue

requirement by the total load in Western's control area. The annual

cost is then divided by 12 months to obtain a monthly charge. Using

1996 data, this methodology for determining the rate for reactive

supply and voltage control has produced a charge of $0.08/kW-month for

transmission capacity reserved.

8. Proposed Rate for Regulation and Frequency Response Service

Regulation and frequency response service in the east side of the

control area is provided primarily by Oahe generation and in the west

side of the control area by Fort Peck, both of which are Corps of

Engineers (Corps) facilities. The Corps generation fixed charge rate is

applied to Oahe and Fort Peck net plant costs producing an annual

generation revenue requirement for the Oahe and Fort Peck power plants.

This revenue requirement is divided by the capacity at the plants to

derive a dollar per kilowatt charge for Oahe's and Fort Peck's

installed capacity. This dollar per kilowatt charge is then applied to

capacity used at Oahe and Fort Peck for regulation and frequency

response service in the control area. The capacity used for regulation

and frequency response service has been determined to be 4 percent of

the annual peak load. The 4 percent value was derived by averaging the

incremental change in hourly load in the control area for the calendar

year. The annual revenue requirement for regulation and frequency

response service is determined by applying the dollar per kilowatt

charge to the capacity used for regulation and frequency response. The

regulation and frequency response service charge is then determined by

dividing the revenue requirement by Western's load in the control area.

The annual cost is then divided by 12 months to obtain a monthly

charge. Using 1996 data, this methodology for determining the rate for

regulation and frequency response produced a charge of $0.09/kW-month

of load for which Western is providing this service. This rate and rate

design is recovering Western's revenue requirement only. Credit will be

given to those transmission customers who provide Western with

Automatic Generation Control (AGC) of generation facilities capable of

providing this service.

9. Proposed Rate for Energy Imbalance Service

This service is not intended to provide backup for generation

supply. Energy shall be returned with like energy (on peak with on

peak, etc.) and accounts zeroed out monthly. Western reserves the right

to apply a penalty to energy imbalances outside a 3 percent bandwidth

(+/-1.5 percent deviation). The penalty for under deliveries outside

the 3 percent bandwidth is 100 mills/kWh. Over deliveries outside the 3

percent bandwidth will be forfeited to the control area

10. Proposed Rate for Reserves

Western's annualized cost for reserves is determined by multiplying

the P-SMBP-ED generation net plant costs by the generation fixed charge

rate. The cost/kW-year is determined by dividing the plant costs by the

plant capacity. The capacity used for reserves is determined by

multiplying the peak IS load in the control area by the MAPP

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operating reserve requirement. The cost/kW-year is multiplied by the

capacity used for reserves to determine the annual cost of reserves.

The annual cost of reserves is divided by Western's peak load in the

control area to calculate the annual charge. The annual cost is then

divided by 12 months to obtain a monthly charge. Using 1996 data, this

methodology for determining the reserve rate has produced a charge of

$0.12/kW-month of customer load. This rate and rate design is

recovering only Western's revenue requirement. If energy is taken under

this service the energy charge will be the MAPP Rate for Emergency

Energy, which is currently 30 mills/kWh.

Table 1.--Proposed Service Rate Formulas for New Transactions

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Service Rate formula 1996 data Rate based on 1996 data

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Network Transmission................. Customer's Load Ratio Customer's Load Ratio For comparison estimate

Share * 1/12 * (Annual Share * 1/12 * at $3.07/kW-Mo.

Transmission Revenue ($116.4M--$12.6M).

Requirement--Non-Firm

Revenue Credits).

Firm Point-to-Point Transmission..... (Total Annual Revenue ($116.4M--$12.6M)/2,819 $3.07/kW-Mo.

Requirement--Non-Firm MW/12 months.

Revenue Credits)/

Annual Average

Transmission System

Monthly Peak Load/12

months.

Non-Firm Point-to-Point Transmission. Firm Point-to-Point $3.07/kW--Mo/730 hours/ 4.20 Mills/kWh.

rate/730 hours per month.

month.

Scheduling, System Control, and Transmission fixed 20.59% * $6.86M/25,915 $54.50/schedule/day.

Dispatch. charge rate* ((.4137 * daily schedules per

Watertown net plant) + year.

(.384 * communications

net plant))/number of

daily schedules per

year.

Reactive Supply and Voltage Control.. ((Generation fixed ((12.3%* $613.2M * $0.08/kW-Mo.

charge rate * 2.02%) + $1M)/2,532 MW-

generation net plant yr/12 months.

cost * capability used

for reactive support)

+ Basin Electric and

Heartland revenue

requirement)/load in

control area/12 months.

Regulation and Frequency Response.... COE fixed charge rate * 10.4% * $251.6M/937 MW $0.09/kW-Mo.

COE generation net * 64.6 MW/1,615 MW/12

plant cost/plant months.

capacity * capacity

used for regulation/

Western's load in

control area/12 months.

Energy Imbalance..................... Penalty................ 100 mills/kWh charge .......................

for under deliveries

outside 3% bandwidth(+/

-1.5%). Over

deliveries outside 3%

bandwidth forfeited to

the control area.

Reserves............................. Generation fixed charge 12.3% * $613.2M/2,517 $0.12/kW-Mo.

rate * generation net MW * 80.75 MW/1,615 MW/

plant cost/plant 12 months.

capacity * capacity

used for reserves/

Western's load in

control area/12 months.

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IV. Cost Shifting

There is no immediate impact to the P-SMBP-ED firm power rate. In

the first few years as new electric service arrangements move to the

IS, costs will shift between the IS participants. Western will incur

approximately $1 million/year of additional transmission cost,

Heartland will incur approximately $200,000/year of additional

transmission cost and Basin Electric's costs will be reduced

approximately $2.4 million/year, based upon average Pick-Sloan

generation. Western's increased transmission costs will have minimal

impact to the P-SMBP-ED firm power rate. Although it is difficult to

project cost shifting among the IS participants beyond the first few

years following the implementation of this proposal, additional usage,

and increased revenues should occur as existing transmission contracts

terminate and are reformulated. This should mitigate the impact to the

participants. Transition payments among the IS participants may be

considered to mitigate impacts or cost shifts if in this public process

the impacts are determined to be too severe.

V. Other Options

All other options mentioned in the Advance Announcement are

evaluated in the customer rate brochure. The additional comment item of

generation based rates is also examined in the customer rate brochure.

VI. Authorities

Transmission and ancillary services rates for the P-SMBP-ED are

being established pursuant to the Department of Energy Organization Act

(42 U.S.C. 7101 et. seq.) and the Reclamation Act of 1902 (43 U.S.C.

371 et. seq.), as amended and supplemented by subsequent enactments,

particularly section 9(c) of the Reclamation Project Act of 1939 (43

U.S.C. 485h(c)) and section 5 of the Flood Control Act of 1944 (16

U.S.C. 825s) and other acts specifically applicable to the projects

involved.

By Amendment No. 3 to Delegation Order No. 0204-108, published

November 10, 1993 (58 FR 59716), the Secretary of DOE delegated (1) the

authority to develop long-term power and transmission rates on a

nonexclusive basis to the Administrator of Western; (2) the authority

to confirm, approve, and place such rates into effect

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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 FERC. Existing DOE procedures for

public participation in power rate adjustments are found at 10 CFR part

903.

Regulatory Flexibility Analysis

Pursuant to the Regulatory Flexibility Act of 1980 (5 U.S.C. 601,

et. seq.), each agency, when required 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

IS transmission rate and ancillary service rate adjustments are related

to non-regulatory services provided by Western at particular rates.

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 IS transmission rates and ancillary services are of

limited applicability, no flexibility analysis is required.

Environmental Compliance

Western will conduct an environmental evaluation of the proposed

rates and develop the appropriate level of environmental documentation

pursuant to the National Environmental Policy Act (NEPA) of 1969 (42

U.S.C. 4321 et. seq.); the Council on Environmental Quality Regulations

for implementing NEPA (40 CFR parts 1500 through 1508); and the DOE

NEPA Implementing Procedures and Guidelines (10 CFR part 1021).

Review Under the Paperwork Reduction Act

In accordance with the Paperwork Reduction Act of 1980, (44 U.S.C.

3501 et. seq.), Western has received approval from the Office of

Management and Budget for the collection of customer information in

this rule, under control number 1910-0100.

Determination Under Executive Order 12866

DOE has determined that this is not a significant regulatory action

because it does not meet the criteria of Executive Order 12866, 58 FR

51735. Western has an exemption from centralized regulatory review

under Executive Order 12866; accordingly, no clearance of this notice

by Office of Management and Budget is required.

Availability of Information

All brochures, studies, comments, letters, memoranda, or other

documents made or kept by Western for developing the proposed rates,

will be made available for inspection and copying at the Upper Great

Plains Regional Office, located at 2900 4th Avenue North, Billings, MT

59107-5800, during normal business hours.

Dated: September 5, 1997.

Michael S. Hacskaylo,

Acting Administrator.

[FR Doc. 97-24346 Filed 9-12-97; 8:45 am]

BILLING CODE 6450-01-P