Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices 55821 

DEPARTMENT OF ENERGY 

Western Area Power Administration 

Pick-Sloan Missouri Basin Program—

Eastern Division Transmission and 

Ancillary Services-Rate Order No. 

WAPA–122 

AGENCY: Western Area Power 

Administration, DOE. 

ACTION: Notice of Order Concerning 

Transmission and Ancillary Services 

Rates. 

SUMMARY: The Deputy Secretary of 

Energy confirmed and approved Rate 

Order No. WAPA–122 and Rate 

Schedules UGP–FPT1, UGP–NFPT1, 

UGP–NT1, UGP–AS1, UGP–AS2, UGP–

AS3, UGP–AS4, UGP–AS5, and UGP–

AS6 placing the Integrated System (IS) 

Transmission and Ancillary Services 

rate into effect on an interim basis. The 

provisional rates will be in effect until 

the Federal Energy Regulatory 

Commission (Commission) confirms, 

approves, and places them into effect on 

a final basis or until they are replaced 

by other rates. The provisional rates will 

provide sufficient revenue to pay all 

annual costs, including interest 

expense, and repayment of required 

investment, within the allowable 

periods. 

DATES: Rate Schedules UGP–FPT1, 

UGP–NFPT1, UGP–NT1, UGP–AS1, 

UGP–AS2, UGP–AS3, UGP–AS4, UGP–

AS5, and UGP–AS6 will be placed into 

effect on an interim basis on the first 

day of the first full billing period 

beginning on or after October 1, 2005, 

and will be in effect until the 

Commission confirms, approves, and 

places the rate schedules in effect on a 

final basis through September 30, 2010, 

or until the rate schedules are 

superseded. These new rate schedules 

dated October 2005, supersede the 

similarly titled rate schedules dated 

1998. 

FOR FURTHER INFORMATION CONTACT: Mr. 

Robert J. Harris, Upper Great Plains 

Regional Manager, Western Area Power 

Administration, 2900 4th Avenue North, 

Billings, MT 59101–1266, telephone 

(406) 247–7405, or Mr. Jon R. Horst, 

Rates Manager, Upper Great Plains 

Region, Western Area Power 

Administration, 2900 4th Avenue North, 

Billings, MT 59101–1266, telephone 

(406) 247–7444, e-mail horst@wapa.gov. 

SUPPLEMENTARY INFORMATION: The 

Deputy Secretary of Energy approved 

existing Rate Schedules UGP–FPT1, 

UGP–NFPT1, UGP–NT1, UGP–AS1, 

UGP–AS2, UGP–AS3, UGP–AS4, UGP–

AS5, and UGP–AS6 for IS Transmission 

and Ancillary Service rates on August 1, 

1998, in Rate Order No. WAPA–79. The 

Commission confirmed and approved 

the rate schedules on November 25, 

1998, in FERC Docket No. EF98–5031–

000. These rate schedules were then 

extended through September 30, 2005, 

by Rate Order No. WAPA–100, which 

was confirmed and approved by the 

Commission on December 16, 2003, 

under FERC Docket No. EF03–5032–

000. The rate schedules for Rate Order 

No. WAPA–79 and Rate Order No. 

WAPA–100 contained formulary rates 

that were recalculated yearly using the 

fixed charge rate methodology. The 

provisional formula rates will continue 

to use the fixed charge rate methodology 

and will continue to be recalculated 

yearly from updated financial and load 

data. However, the Generator Step Up 

Transformers are to be removed from 

the annual revenue requirement for IS. 

After the approval of the original 

Transmission and Ancillary Service 

rates for the IS, the Commission decided 

that Generator Step Up Transformers 

should not be included in transmission 

rates for jurisdictional utilities. 

Consistent with Western’s goal to 

observe Commission precedent to the 

extent consistent with its mission and 

permitted by law and regulation, the IS 

Transmission and Ancillary Service 

rates are being modified. 

The existing IS Long-Term Firm and 

Short-Term Firm Point-to-Point 

Transmission Service Rate Schedule is 

superseded by Rate Schedule UGP–

FPT1, dated October 2005. The 2004–

2005 existing rate for IS Long-Term 

Firm and Short-Term Firm Point-toPoint Transmission Service is $2.72 per 

kilowattmonth (kWmonth). The 

provisional rate for IS Long-Term Firm 

and Short-Term Firm Point-to-Point 

Transmission Service is $2.69/ 

KWmonth. Under Rate Schedule UGP–

NFPT1, the existing rate calculation for 

IS Non-Firm Point-to-Point 

Transmission Service is 3.73 mills per 

kilowatthour (mills/kWh). The 

provisional rate for IS Non-Firm Pointto Point Transmission Service is 3.68 

mills/kWh. Under Rate Schedule UGP–

NT1 the existing annual revenue 

requirement for IS Network Integration 

Transmission Service is $128,017,923. 

The provisional annual revenue 

requirement for IS Network Integration 

Transmission Service is $126,741,576. 

Under Rate Schedule UGP–AS1, the 

existing rate for Scheduling System 

Control and Dispatch (Scheduling and 

Dispatch) Service is $49.29/schedule/ 

day. The provisional rate for Scheduling 

and Dispatch is $49.77/schedule/day. 

Under Rate Schedule UGP–AS2, the 

existing rate for Reactive Supply and 

Voltage Control from Generation 

Sources Service (Reactive Service) is 

$0.06/kWmonth. The provisional rate 

for Reactive Service is $0.07/kWmonth. 

Under Rate Schedule UGP–AS3, the 

provisional rate calculated for 

Regulation and Frequency Response 

Service is unchanged from the existing 

rate of $0.04/kWmonth. Under Rate 

Schedule UGP–AS4, there is no change 

in the rate for Energy Imbalance Service 

between the existing and the proposed 

rates. Under Rate Schedules UGP–AS5 

and UGP–AS6, the rate for Spinning and 

Supplemental Reserves is $0.11/ 

kWmonth. The provisional rate 

calculated for Spinning and 

Supplemental Reserves is $0.12/ 

kWmonth. 

By Delegation Order No. 00–037.00, 

effective December 6, 2001, the 

Secretary of Energy delegated: (1) The 

authority to develop power and 

transmission rates to Western’s 

Administrator, (2) the authority to 

confirm, approve, and place such rates 

into effect on an interim basis to the 

Deputy Secretary of Energy, 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 part 903) were 

published on September 18, 1985. 

Under Delegation Order Nos. 00–

037.00 and 00–001.00A, 10 CFR part 

903, and 18 CFR part 300, I hereby 

confirm, approve, and place Rate Order 

No. WAPA–122, the proposed IS Firm 

and Non-Firm Transmission and 

Ancillary Service rates into effect on an 

interim basis. The new Rate Schedules 

UGP–FPT1, UGP–NFPT1, UGP–NT1, 

UGP–AS1, UGP–AS2, UGP–AS3, UGP–

AS4, UGP–AS5, and UGP–AS6 for IS 

Transmission and Ancillary Service 

rates will be promptly submitted to the 

Commission for confirmation and 

approval on a final basis. 

Dated: September 13, 2005. 

Clay Sell, 

Deputy Secretary. 

[Rate Order No. WAPA–122] 

In the matter of: Western Area Power 

Administration Rate Adjustment for the PickSloan Missouri Basin Program—Eastern 

Division Transmission and Ancillary 

Services; Order Confirming, Approving, and 

Placing the Pick-Sloan Missouri Basin 

Program—Eastern Division Transmission and 

Ancillary Services Formula Rates Into Effect 

on an Interim Basis 

This rate was established in 

accordance with section 302 of the 

Department of Energy (DOE) 

Organization Act (42 U.S.C. 7152). This 

Act transferred to and vested in the 

55822 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices 

Secretary of Energy the power marketing 

functions of the Secretary of the 

Department 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 laws, 

particularly section 9(c) of the 

Reclamation Project Act of 1939 (43 

U.S.C. 485h(c)), section 5 of the Flood 

Control Act of 1944 (16 U.S.C. 825s), 

and other Acts that specifically apply to 

the project involved. 

By Delegation Order No. 00–037.00, 

effective December 6, 2001, the 

Secretary of Energy delegated: (1) The 

authority to develop power and 

transmission rates to Western’s 

Administrator, (2) the authority to 

confirm, approve, and place such rates 

into effect on an interim basis to the 

Deputy Secretary of Energy, 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 part 903) were 

published on September 18, 1985. 

Acronyms and Definitions 

As used in this Rate Order, the 

following acronyms and definitions 

apply: 

$/kWmonth: Monthly charge for 

capacity (i.e., $ per kilowatt (kW) per 

month). 

12-cp: 12-month coincident peak 

average. 

Administrator: The Administrator of 

the Western Area Power 

Administration. 

Ancillary Services: Those services 

necessary to support the transfer of 

electricity while maintaining reliable 

operation of the transmission system in 

accordance with standard utility 

practice. 

A&GE: Administrative and general 

expense. 

Balancing Authority: An electric 

system or systems, bounded by 

interconnection metering and telemetry, 

capable of controlling generation to 

maintain its interchange schedule with 

other Balancing Authorities and 

contributing to frequency regulation of 

the Interconnection. Formerly known as 

control area. 

Basin Electric: Basin Electric Power 

Cooperative. 

Capacity: The electric capability of a 

generator, transformer, transmission 

circuit, or other equipment. It is 

expressed in kilowatts. 

Capacity Rate: The rate which sets 

forth the charges for capacity. It is 

expressed in $/kWmonth. 

Commission: Federal Energy 

Regulatory Commission. 

Corps of Engineers: U.S. Army Corps 

of Engineers. 

Customer: An entity with a contract 

that is receiving service from Western’s 

UGPR. 

DOE: United States Department of 

Energy. 

DOE Order RA 6120.2: An order 

outlining power marketing 

administration financial reporting and 

ratemaking procedures. 

Energy: Measured in terms of the 

work capacity over a period of time. It 

is expressed in kilowatthours. 

Emergency Energy: Electric energy 

purchased by an electric utility 

whenever an event on the system causes 

insufficient operating capability to cover 

its own demand requirement. 

Energy Imbalance Service: A service 

which provides energy correction for 

any hourly mismatch between a 

Transmission Customer’s energy supply 

and the demand served. 

Energy Rate: The rate which sets forth 

the charges for energy. It is expressed in 

mills per kilowatthour and applied to 

each kilowatthour delivered to each 

customer. 

FERC: The Commission (to be used 

when referencing Commission Orders). 

FERC Order No. 888: FERC Order 

Nos. 888, 888–A, 888–B and 888–C 

unless otherwise noted. 

Firm: A type of product and/or service 

available at the time requested by the 

customer. 

Firm Point-to-Point: Service that is 

reserved and/or scheduled between 

Points of Receipt and Delivery. 

FRN: Federal Register notice. 

FY: Fiscal year; October 1 to 

September 30. 

GSU: Generator Step Up Transformer. 

GWh: Gigawatthour—the electrical 

unit of energy that equals 1 billion 

watthours or 1 million kWh. 

Heartland: Heartland Consumers 

Power District. 

IS: Integrated System. 

ISO: Independent System Operator. 

JTS: Joint Transmission System. 

kW: Kilowatt—the electrical unit of 

capacity that equals 1,000 watts. 

kWh: Kilowatthour—the electrical 

unit of energy that equals 1,000 watts in 

1 hour. 

kWmonth: Kilowattmonth—the 

electrical unit of the monthly amount of 

capacity. 

kWyear: Kilowattyear—the electrical 

unit of the yearly amount of capacity. 

Load: The amount of electric power or 

energy delivered or required at any 

specified point(s) on a system. 

Load-ratio share: Ratio of the Network 

Transmission Customer’s coincident 

hourly load (including its designated 

network load not physically 

interconnected with the Transmission 

Provider) to the Transmission Provider’s 

monthly Transmission System peak, 

calculated on a rolling 12-month basis. 

Long-Term Firm Point-to-Point: Firm 

Point-to-Point Transmission Service 

reservation with at least 12 consecutive 

equal monthly amounts. 

MAPP: Mid-Continent Area Power 

Pool. 

MBMPA: Missouri Basin Municipal 

Power Agency. 

Mill: A monetary denomination of the 

United States that equals one tenth of a 

cent or one thousandth of a dollar. 

Mills/kWh: Mills per kilowatthour—

the unit of charge for energy. 

MVAR: Megavar, equal to 1,000,000 

VARs. 

MW: Megawatt—the electrical unit of 

capacity that equals 1 million watts or 

1,000 kilowatts. 

NERC: North American Electric 

Reliability Council. 

Net Revenue: Revenue remaining after 

paying all annual expenses. 

Network Customer: An entity 

receiving Transmission Service under 

the terms of the Transmission Provider’s 

Network Integration Transmission 

Service of the Tariff. 

Non-Firm Point-to-Point: Point-toPoint Transmission Service under the 

Tariff that is reserved and scheduled on 

an as-available basis and is subject to 

interruption for economic reasons. 

O&M: Operation and maintenance. 

OASIS: Open Access Same-Time 

Information System—provides access to 

information on transmission pricing and 

availability for potential transmission 

customers. 

OM&R: Operation, Maintenance & 

Replacement. 

P–SMBP: Pick-Sloan Missouri Basin 

Program. 

P–SMBP—ED: Pick-Sloan Missouri 

Basin Program—Eastern Division. 

Point-to-Point: The reservation and 

transmission of capacity and energy on 

either a firm or non-firm basis from 

designated Point(s) of Receipt to 

designated Point(s) of Delivery. 

Power: Capacity and energy. 

Provisional Rate: A rate which has 

been confirmed, approved, and placed 

into effect on an interim basis by the 

Deputy Secretary. 

Rate Brochure: An April 2005 

document explaining the rationale and 

background for the rate proposal 

contained in this Rate Order. 

Reclamation: United States 

Department of the Interior, Bureau of 

Reclamation. 

Reclamation Law: A series of Federal 

laws. Viewed as a whole, these laws 

Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices 55823 

create the framework under which 

Western markets power. 

Reactive Supply and Voltage Control 

from Generating Sources Service: A 

service which provides reactive supply 

through changes to generator reactive 

output to maintain transmission line 

voltage and facilitate electricity 

transfers. 

Regulation and Frequency Response 

Service: A service which provides for 

following the moment-to-moment 

variations in the demand or supply in 

a Balancing Authority and maintaining 

scheduled interconnection frequency. 

Reserve Services: Spinning Reserve 

Service and Supplemental Reserve 

Service. 

Revenue Requirement: The revenue 

required to recover annual expenses 

(such as O&M, purchase power, 

transmission service expenses, interest, 

and deferred expenses) and repay 

Federal investments, and other assigned 

costs. 

SCADA: Supervisory Control and Data 

Acquisition. 

Schedule: An agreed-upon transaction 

size (megawatts), beginning and ending 

ramp times and rate, and type of service 

required for delivery and receipt of 

power between the contracting parties 

and the Balancing Authority(ies) 

involved in the transaction. 

Scheduling, System Control and 

Dispatch Service: A service which 

provides for (a) scheduling, (b) 

confirming and implementing an 

interchange schedule with other 

balancing authorities, including 

intermediary balancing authorities 

providing transmission service, and (c) 

ensuring operational security during the 

interchange transaction. 

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 

with service duration of less than one 

year. 

Spinning Reserve Service: Generation 

capacity needed to serve load 

immediately in the event of a system 

contingency. Spinning Reserve Service 

may be provided by generating units 

that are on-line and loaded at less than 

maximum output. The Transmission 

Provider must offer this service when 

the transmission service is used to serve 

load within its Balancing Authority. The 

Transmission Customer must either 

purchase this service from the 

Transmission Provider or make 

alternative comparable arrangements to 

satisfy its Spinning Reserve Service 

obligation. 

Supplemental Reserve Service: 

Generation capacity 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. 

Supplemental Reserve Service may be 

provided by generation units that are 

on-line but unloaded, by quick start 

generation or by interruptible load. The 

Transmission Provider must offer this 

service when the transmission service is 

used to serve load within its Balancing 

Authority. The Transmission Customer 

must either purchase this service from 

the Transmission Provider or make 

alternative comparable arrangements to 

satisfy its Supplemental Reserve Service 

obligation. 

Supporting Documentation: A 

compilation of data and documents that 

support the Rate Brochure and the rate 

proposal. 

System: An interconnected 

combination of generation, transmission 

and/or distribution components 

comprising an electric utility, 

independent power producer(s) (IPP), or 

group of utilities and IPP(s). 

Tariff: Western Area Power 

Administration Open Access 

Transmission Service Tariff, originally 

approved in Docket No. NJ98–1–000, 99 

FERC ¶ 61,062 (2002) and amended in 

Docket No. NJ05–1–000, 112 FERC 

¶ 61,044 (2005). 

Transmission Customer: Any eligible 

customer (or its designated agent) that 

receives transmission service under the 

Tariff. 

Transmission Provider: Any utility 

that owns, operates, or controls facilities 

used to transmit electric energy in 

interstate commerce. The UGPR, as 

operator of the IS, is the Transmission 

Provider for the purposes of this Federal 

Register notice. 

Transmission System: The facilities 

owned, controlled, or operated by the 

Transmission Provider that are used to 

provide transmission service. 

Transmission System Total Load: The 

12-cp peak for Network Transmission 

Service plus reserved capacity for all 

Firm Point-to-Point Transmission 

Service. 

UGPR: The Upper Great Plains 

Customer Service Region of the Western 

Area Power Administration. In some 

places in this order, UGPR maybe 

referenced generically as Western. 

VAR: A unit of reactive power. 

WAUGP: The NERC acronym for the 

Western Area Upper Great Plains 

Balancing Authority. This balancing 

authority is also known as the 

Watertown Balancing Authority. 

Watertown Operation Office: Western 

Area Power Administration Upper Great 

Plains Customer Service Region, 

Operations Office, 1330 41st Street SE., 

Watertown, South Dakota. 

Western: United States Department of 

Energy, Western Area Power 

Administration. 

Western Regions: Customer service 

regions of the Western Area Power 

Administration. 

Western’s Tariff: Western’s Open 

Access Transmission Service Tariff. 

Effective Date 

The new interim rates will take effect 

on the first day of the first full billing 

period beginning on or after October 1, 

2005, and will remain in effect until 

September 30, 2010, pending approval 

by the Commission on a final basis. 

Public Notice and Comment 

Western followed the Procedures for 

Public Participation in Power and 

Transmission Rate Adjustments and 

Extensions, 10 CFR part 903, for a minor 

rate adjustment in developing these 

rates. The steps Western took to involve 

interested parties in the rate process 

were: 

1. The proposed rate adjustment 

process began February 9, 2005, when 

Western mailed a notice announcing an 

informal customer meeting to all IS 

Transmission Customers and interested 

parties. The meeting was held on March 

22, 2005, in Sioux Falls, South Dakota. 

At this informal meeting, Western 

explained the rationale for the rate 

adjustment, presented rate designs and 

methodologies, and answered questions. 

2. A Federal Register notice 

published on April 18, 2005, (70 FR 

20119), announced the proposed rates 

for P–SMBP—ED Transmission and 

Ancillary Service rates, and began a 

public consultation and comment 

period. 

3. On April 28, 2005, Western mailed 

letters to all IS Transmission Customers 

and interested parties transmitting the 

Federal Register notice published on 

April 18, 2005, and directing them to 

the rate brochure on Western’s Web site. 

4. Western received no comment 

letters during the consultation and 

comment period, which ended May 18, 

2005. 

Project Description 

The initial stages of the Missouri 

River Basin Project were authorized by 

section 9 of the Flood Control Act of 

1944 (58 Stat. 887, 890, Pub. L. 78–534). 

It was later renamed the P–SMBP. The 

P–SMBP is a comprehensive program, 

with the following authorized functions: 

flood control, navigation improvement, 

irrigation, municipal and industrial 

water development, and hydroelectric 

55824 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices 

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 UGPR markets significant 

quantities of Federally-generated 

hydroelectric power from the P–

SMBP—ED. Western owns and operates 

an extensive system of high-voltage 

transmission facilities which the UGPR 

uses to market approximately 2,400 MW 

of capacity from Federal projects within 

the Missouri River Basin. This capacity 

is generated by eight powerplants 

located in Montana, North Dakota, and 

South Dakota. The UGPR uses the 

transmission facilities of Western and 

others to market this power and energy 

to customers located within the P–

SMBP—ED. This marketing area 

includes Montana, east of the 

Continental Divide, all of North and 

South Dakota, eastern Nebraska, western 

Iowa, and western Minnesota. 

Integrated System Description 

Using a single system, joint-planning 

concept, the UGPR, Basin Electric, and 

Heartland combined their transmission 

facilities to form the IS and developed 

Transmission and Ancillary Service 

rates for transmission over the IS. This 

action was necessary because the UGPR, 

Basin Electric, and Heartland, whose 

facilities are fully integrated, did not 

have rates suitable for long-term open 

access transmission service. The 

transmission facilities included in the IS 

are transmission lines, substations, 

communication equipment and facilities 

related to operation, maintenance, and 

support of the IS Transmission System. 

The UGPR is designated as the operator 

of the other participants’ transmission 

facilities and as such contracts for 

service, determines and posts the 

available transmission capacity on the 

OASIS, bills for service, collects 

payments, and distributes revenues to 

each IS participant. 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, Iowa, Minnesota, 

Missouri, and in addition include 

facilities which interconnect with 

Canada. 

The approach for formation of the IS 

was to include facilities which followed 

the spirit and intent of the FERC Order 

No. 888 and to make the system the 

most useful to all transmission 

requesters. The ‘‘seven-factor test’’

defined in FERC Order No. 888 was 

used to determine the distribution 

facilities that were excluded from the IS 

Transmission System. Several major 

facilities are included in the IS. The 

second 345-kV transmission line 

between the Antelope Valley and 

Leland Olds generation stations, which 

meets the standards for acceptable 

transmission facilities set in the 

Commission rulings on filings by other 

transmission entities, is included. The 

230-kV transmission line between 

Tioga, North Dakota, and Boundary 

Dam, which provides access to 

generation and loads in Canada, is 

included in the IS. The IS also includes 

the Miles City DC tie, which opens the 

markets between the east-west electrical 

separation of the United States and 

increases access to other utilities. 

P–SMBP—ED Transmission and 

Ancillary Service Rates Study 

Western prepared a Transmission and 

Ancillary Service rates study to ensure 

that Transmission and Ancillary Service 

rates are based on the cost of service of 

the IS Transmission System. This study 

includes all IS Transmission and 

Ancillary Service expenses and 

associated offsetting revenues. Western 

charges IS Transmission Service rates 

separately to entities receiving 

transmission-only services over the IS 

Transmission System. 

The UGPR is proposing to continue 

using an annual fixed charge formula 

that will determine how much revenue 

must be recovered from the IS 

Transmission and Ancillary Service 

rates. The annual revenue requirements 

include O&M expenses, administrative 

and general expenses, interest expense, 

and depreciation expense. This 

methodology is applied annually using 

the most recent historical test year. 

These revenue requirements are offset 

by appropriate IS revenues. 

Integrated System Transmission 

Service 

Western will offer Network, Firm 

Point-to-Point, and Non-Firm Point-toPoint Transmission Service on the IS. 

The service offered is the transmission 

of energy and capacity from Points of 

Receipt to Points of Delivery on the IS. 

The IS Transmission Service Rates 

include the cost of Scheduling, System 

Control and Dispatch Service. 

Therefore, an additional charge for this 

ancillary service is not required for 

transmission users. 

Western, Basin Electric, and 

Heartland will take IS Transmission 

Service. Transmission Service to 

Western’s Customers continues to be 

bundled in the firm electric power 

service rate under existing contracts that 

expire in 2020. 

The UGPR prepared a transmission 

service study to ensure that the formula 

IS Transmission and Ancillary Service 

rates are based on the cost of service to 

the IS. The UGPR seeks approval of 

formula rates for calculating Point-toPoint IS Transmission Rates, the 

Network Annual Revenue Requirement 

for IS Transmission Service, and 

ancillary service rates. Western requests 

the Commission confirm that these rates 

are not arbitrary, capricious, or in 

violation of the law. The rates will be 

recalculated every year, effective May 1, 

based on the approved formula rates 

and updated financial and load data. 

The UGPR will provide customers 

notice of changes in the Transmission 

and Ancillary Service rates no later than 

April 1 of each year. 

IS Transmission System Total Load 

The IS Transmission System Total 

Load is the 12-cp system peak for IS 

Network Transmission Service plus the 

reserved capacity for all IS Long-Term 

Firm Point-to-Point Transmission 

Service. 

The IS Transmission System Total 

Load is calculated as follows based 

upon the most recent historical data 

available at the time of the initial rate 

proposal. This included both 2003 and 

2004 data: 

IS Network Transmission Load ................................................................................................................................................. 3,185,000 kW 

Long-Term Firm Point-to-Point Reserved Capacity .................................................................................................................. 743,000 kW 

IS Transmission System Total Load .......................................................................................................................................... 3,928,000 kW 

Annual Costs 

Western calculated the annual costs of 

providing the various IS Transmission 

and Ancillary Services using a 

Commission-recognized methodology 

for annual cost calculation with fixed 

charge rates for various cost 

components. The cost components 

applicable to Western include O&M, 

Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices 55825 

A&GE, depreciation, and the cost of 

capital. These components are 

displayed as fixed charge rates or 

percentages of net investment. These 

fixed charge rates are then summed to 

arrive at a total fixed charge rate 

associated with the particular service for 

which a rate is being calculated. The 

fixed charge rate calculation for the 

various IS Transmission and Ancillary 

Services can be summarized with the 

following formula: 

O&M ÷ Net investment 

+ A&GE ÷ Net investment 

+ Depreciation expense ÷ Net investment 

+Annual interest expense ÷ Unpaid investment balance 

Total fixed charge rate 

To arrive at the annual cost of providing 

the IS Transmission Service or one of 

the Ancillary Services, the total fixed 

charge rate is applied to the net 

investment allocated to the service: 

Total fixed charge rate × Net 

investment = Annual cost of providing 

service. 

The source for the UGPR’s annual 

O&M, A&GE, depreciation expense, 

interest expense, and investment is the 

Results of Operations for the Upper 

Great Plains Customer Service RegionPick Sloan Missouri Basin. The source 

for Heartland’s data is Heartland 

Consumers Power District Annual 

Report. The sources for Basin Electric’s 

data are Basin Electric’s Consolidated 

Financial Statement, Rural Utility 

Service Form 12, and other accounting 

records. 

Annual Revenue Requirement for IS 

Transmission Service 

The annual revenue requirement for 

IS Transmission Service is based upon 

the most recent historical data available 

at the time of the initial rate proposal. 

This data is used in a test year and uses 

an annual fixed charge methodology. 

The rates for IS Transmission Service 

(Network and Point-to-Point) are based 

on a revenue requirement that recovers 

the annual costs of Western, Basin 

Electric, and Heartland associated with 

providing the IS Transmission Service 

plus any facility credit paid to the IS 

Transmission Customers. The annual 

revenue requirement for IS 

Transmission Service includes the cost 

for Scheduling, System Control, and 

Dispatch Service needed to provide 

transmission service. Therefore, an 

additional charge for this ancillary 

service is not required for transmission 

users. The annual transmission costs are 

offset by appropriate Transmission 

Revenue Credits to avoid over-recovery 

of costs. The annual revenue 

requirement for IS Transmission Service 

can be summarized with the following 

formula: 

Annual IS Transmission Costs of UGPR 

+ Annual IS Transmission Costs Basin Electric and Heartland 

+ Transmission Customer Facility Credits 

¥ Transmission Revenue Credits 

Annual Revenue Requirement for IS Transmission Service 

Transmission Customer Facility 

Credits are credits paid to IS 

Transmission Customers for facilities 

that are integrated with the IS and 

increase both the capability and the 

reliability of the IS. The credits are 

addressed in individual agreements and 

appropriate adjustments are made in 

subsequent rate calculations. The IS 

participants will evaluate requests for 

facility credits consistent with the 

Commission’s guidance in the FERC 

Order No. 888, other relevant 

Commission policy, and the terms of the 

Tariff. 

Transmission Revenue Credits 

include revenue from sales of Non-Firm, 

discounted IS Firm and Short-Term 

Firm Point-to-Point Transmission 

Service; revenue from existing 

transmission agreements; and revenue 

from Scheduling, System Control and 

Dispatch Services. 

IS Network Transmission Service 

The proposed rate for IS Network 

Transmission Service is a formula 

calculation based upon the annual 

revenue requirement for IS 

Transmission Service then in effect, as 

determined by the annual fixed charge 

methodology. The monthly charge for IS 

Network Transmission Service is as 

follows: 

Network Customer’s Load-ratio share 

× Annual Revenue Requirement for IS Transmission 

÷ 12 months 

Monthly IS Network Transmission Service Charge 

The load ratio-share is the ratio of the 

Network Customer’s coincident hourly 

load to the monthly IS Transmission 

System peak minus the coincident peak 

for all IS Firm Point-to-Point 

Transmission Service plus the IS Firm 

Point-to-Point reservations, calculated 

on a rolling 12-cp basis. The proposed 

rate formula would be effective October 

1, 2005, through September 30, 2010. 

IS Firm Point-to-Point Transmission 

Service 

The rate for IS Firm Point-to-Point 

Transmission Service is the annual 

revenue requirement for IS 

Transmission Service divided by the IS 

Transmission System Total Load in kW, 

to derive a cost per kilowattyear 

(kWyear). The formula for the monthly 

rate is as follows: 

55826 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices 

Annual Revenue Requirement for IS Transmission 

÷ IS Transmission System Total Load 

÷ 12 months 

Monthly IS Firm Point-to-Point Transmission Rate 

The rate formula is applied annually 

by using the most current historical data 

available. The proposed rate formula 

would be effective October 1, 2005, 

through September 30, 2010. 

IS Non-Firm Point-to-Point 

Transmission Service 

The proposed rate for IS Non-Firm 

Point-to-Point Transmission Service is a 

mills/kWh rate, based upon the current 

firm point-to-point rate and may be 

discounted. The formula rate is as 

follows: 

Monthly IS Firm Point-to-Point Transmission Rate 

÷ 730 hours/month 

× 1000 mills per dollar 

IS Non-Firm Point-to-Point Transmission Rate 

This rate will remain in effect for the 

same period as the IS Firm Point-toPoint Transmission Service rate and 

will also be reviewed annually. The IS 

Non-Firm Point-to-Point Transmission 

Service will be offered at hourly, daily, 

and monthly rates. The IS Transmission 

Service availability will be posted on 

the UGPR OASIS. 

Ancillary Services 

In accordance with the Tariff, Western 

will offer to all customers the six 

ancillary services defined by the 

Commission, two of which IS 

Transmission Customers are required to 

purchase: (1) Scheduling, System 

Control, and Dispatch Service, and (2) 

Reactive Supply and Voltage Control 

from Generation Sources Service. The 

remaining four ancillary services are: (3) 

Regulation and Frequency Response 

Service, (4) Energy Imbalance Service, 

(5) Spinning Reserve Service, and (6) 

Supplemental Reserve Service. The 

open access ancillary service formula 

rates are designed to recover only the 

costs incurred for providing the 

service(s). The charges for ancillary 

services are based on the cost of 

resources used to provide these services. 

Sales of Regulation and Frequency 

Response Service, Energy Imbalance 

Service, Spinning Reserve Service, and 

Supplemental Reserve Service may be 

limited since Western has allocated its 

power resources to preference entities 

under long-term commitments. In 

accordance with the Tariff, if Western is 

unable to provide these services from its 

own resources, an offer will be made to 

purchase the services and pass through 

these costs, including an administrative 

charge to the customer. 

Scheduling, System Control, and 

Dispatch Service 

Western’s annual revenue 

requirement 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 formula rate for Scheduling, System 

Control, and Dispatch Service is: 

Annual Revenue Requirement for 

Scheduling, System Control and Dispatch Service 

÷ Annual Number of Daily Schedules 

Scheduling, System Control and Dispatch Rate 

This rate and rate design only recovers 

Western’s revenue requirement for 

Scheduling, System Control, and 

Dispatch Service. 

Reactive Supply and Voltage Control 

from Generation Sources Service 

Western’s annual cost of providing 

Reactive Supply and Voltage Control 

from Generation Sources Service is 

determined by multiplying the total P–

SMBP—ED generation net plant by the 

generation fixed charge rate. The annual 

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 requirement 

is based on the annual cost of 

equipment installed on its generators to 

provide this service. Western’s, Basin 

Electric’s, and Heartland’s annual 

revenue requirements are summed for 

the total revenue requirement for this 

service. The Reactive Supply and 

Voltage Control Service from Generation 

Sources Service rate is then derived by 

dividing the total annual revenue 

requirement by the load requiring 

reactive service. The annual rate is then 

divided by 12 months to obtain a 

monthly rate. The Reactive Supply and 

Voltage Control rate calculation is 

summarized in the following formula: 

Annual Reactive Revenue Requirement 

+ Load Requiring Reactive Service 

÷ 12 months 

Monthly Reactive Rate 

Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices 55827 

Regulation and Frequency Response 

Service 

Regulation and Frequency Response 

Service in the east side of the balancing 

authority is provided primarily by Oahe 

generation and in the west side of the 

balancing authority by Fort Peck 

generation, both of which are Corps of 

Engineer facilities. To calculate the 

annual cost of providing Regulation and 

Frequency Response Service, the Corps 

of Engineers’ generation fixed charge 

rate is applied to Oahe generation and 

Fort Peck generation net plant 

investment. This cost is divided by the 

capacity at the plants to derive a dollar 

per kilowatt amount for Oahe and Fort 

Peck powerplants’ installed capacity. 

This dollar per kilowatt amount is then 

applied to the capacity of Oahe 

generation and Fort Peck generation 

reserved for Regulation and Frequency 

Response Service in the balancing 

authority. The capacity reserved for 

Regulation and Frequency Response 

Service has been determined to be 2 

percent of the annual peak load. The 2 

percent value was derived by averaging 

yearly peak condensing as percentage of 

load for five years. Western’s annual 

revenue requirement for Regulation and 

Frequency Response Service is 

determined by applying the dollar per 

kilowatt amount to the capacity used for 

Regulation and Frequency Response 

Service. Basin Electric’s and Heartland’s 

annual revenue requirement is based on 

the annual cost of equipment installed 

on its generators to provide this service. 

Western’s, Basin Electric’s, and 

Heartland’s annual revenue 

requirements are summed for the total 

revenue requirement for this service. 

Annual rate for Regulation and 

Frequency Response Service is then 

determined by dividing the total 

revenue requirement by the total load in 

the Balancing Authority. The annual 

rate is then divided by 12 months to 

obtain a monthly rate. The Regulation 

and Frequency Response Service rate 

calculation is summarized in the 

following formula: 

Annual Revenue Requirement for Regulation 

+ Load in the Balancing Authority Requiring Regulation 

÷ 12 months 

Monthly Regulation and Frequency Response Rate 

Energy Imbalance Service 

This service is not intended to 

provide backup for generation supply. 

Energy shall be returned in like time 

frames (on-peak, off-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 bandwidth 

will be forfeited to the balancing 

authority. 

Reserve Services 

Western’s annual cost of generation 

for Reserve Services is determined by 

multiplying the generation fixed charge 

rate by the P–SMBP—ED generation net 

plant investment. The cost/kW year is 

determined by dividing the annual cost 

of generation by the plant capacity. The 

capacity used for Reserve Services is 

determined by multiplying Western’s 

peak IS load by the MAPP operating 

reserve requirement of 5 percent. The 

cost/kW year is multiplied by the 

capacity used for Reserve Services to 

determine the annual revenue 

requirement for Reserve Services. The 

annual revenue requirement for Reserve 

Services is divided by Western’s peak 

transmission load to calculate the 

annual rate. The annual rate is then 

divided by 12 months to obtain a 

monthly rate. This rate and rate design 

recovers only Western’s revenue 

requirement associated with Reserve 

Services. If energy is taken under these 

services, the energy charge will be the 

MAPP or its successors rate for 

emergency energy. The Regulation and 

Frequency Response Service rate 

calculation is summarized in the 

following formula: 

Annual Revenue Requirement for Reserves 

÷ Load Requiring Reserves 

÷ 12 months 

Monthly Reserve Service Rate 

Existing and Provisional Rates 

The revenue requirements for the 

individual services and comparison 

values are outlined in the following 

table. These rates are calculated 

comparing the Existing Revenue 

Requirement to the Revenue 

Requirement based upon the most 

recent historical data available at the 

time of the initial rate proposal. 

TABLE 1 

Service Existing revenue 

requirement 

Provisional 

revenue 

requirement 

Percentage 

change 

Transmission ............................................................................................................................ $128,017,923 $126,741,576 ¥0.997 

Scheduling, System Control and Dispatch .............................................................................. 3,373,281 3,406,102 ¥0.973 

Reactive Supply and Voltage Control from Generation Sources ............................................ 2,736,253 3,065,568 12.035 

Regulation and Frequency Control .......................................................................................... 1,065,771 1,075,623 0.924 

Reserves .................................................................................................................................. 1,895,268 2,009,276 6.015 

55828 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices 

Certification of Rates 

Western’s Administrator certifies that 

the IS Transmission and Ancillary 

Service rates placed into effect on an 

interim basis are the lowest possible 

rates consistent with sound business 

principles. The provisional formula 

rates were developed following 

administrative policies and applicable 

laws. 

IS Transmission Service Discussion 

Western proposes continuing the 

annual fixed charge formula to 

determine the Annual Revenue 

Requirement for IS Transmission 

Service. The annual revenue 

requirement for IS Transmission Service 

includes O&M expense, A&GE, interest 

expense, and depreciation expense from 

the most recent historical test year. This 

annual revenue requirement for IS 

Transmission Service is offset by 

appropriate revenue credits. 

The IS Transmission System includes 

the transmission facilities owned by 

Western, Basin Electric, Heartland and 

others in which the IS has contractual 

rights. The costs paid to others for 

contractual rights on their transmission 

lines are included in the costs recovered 

by the annual revenue requirement for 

IS Transmission Service. 

Western will continue to offer 

Network, Firm Point-to-Point, and NonFirm Point-to-Point Transmission 

Service on the IS Transmission System. 

The service offered is the transmission 

of energy and capacity from Points of 

Receipt to Points of Delivery on the IS. 

The IS Transmission Service rates 

include the cost of Scheduling, System 

Control, and Dispatch Service. 

Therefore an additional charge for this 

ancillary service is not required for 

transmission users. 

The provisional IS Transmission 

Service rates will be applied to 

customers who purchase transmission 

services. Western, Basin Electric, and 

Heartland will take IS Transmission 

Service. The IS Transmission Service to 

the UGPR’s Customers will continue to 

be bundled in the firm electric service 

rate under existing contracts that expire 

in 2020. 

IS Transmission System Total Load 

The IS Transmission System Total 

Load is the 12-cp system peak for 

Network IS Transmission Service plus 

the reserved capacity for all IS LongTerm Firm Point-to-Point Transmission 

Service. For the provisional rate, the IS 

Transmission System Total Load will be 

unchanged at 3,968,000 kW. 

Annual Costs 

Western will continue to use a 

Commission-recognized methodology 

for annual cost calculation with fixed 

charge rates for various cost components 

approved by the Commission in WAPA–

79 and WAPA–100. The change in the 

provisional rate is that the costs 

associated with the GSUs are no longer 

included in the net plant investment for 

transmission or the various expenses. 

The investment and costs for GSUs are 

now in the generation fixed charge 

calculation in support of ancillary 

services. The proposed methodology 

will continue to be an annual fixed 

charge formula that will determine the 

annual revenue requirement to be 

recovered from transmission services. 

Annual Revenue Requirement for IS 

Transmission 

A change in the costs that comprise 

the annual revenue requirement for IS 

Transmission is being proposed. The 

proposed transmission rate 

methodology is different from the 

current transmission rate methodology 

in one area. The GSU investments are 

removed from the transmission 

investments and placed in the 

generation investments. This also moves 

the corresponding costs of GSUs from 

transmission costs to generation costs. 

The existing annual revenue 

requirement for IS Transmission Service 

is $128,017,923. The provisional 

Annual Revenue Requirement for IS 

Transmission Service is $126,741,576. 

Network 

The current IS Network Transmission 

Service schedule expires on September 

30, 2005. The provisional annual 

revenue requirement for IS 

Transmission Service will be used in 

the provisional rate formula for IS 

Network Transmission Service. The 

provisional charge for the monthly 

demand for IS Network Transmission 

Service will be the product of the 

network customer’s load ratio share 

times one-twelfth (1/12) of the annual 

revenue requirement for IS 

Transmission Service. The load ratio 

share will be based on the network 

customer’s hourly load (including its 

designated network load not physically 

interconnected with Western), 

coincident with the IS monthly 

transmission system peak, which will be 

calculated on a rolling 12-cp basis. 

Western’s transmission system peak 

includes the sum of capacity reserved 

for IS Point-to-Point Transmission 

Service, 12-cp monthly entitlements for 

firm power customers, and the average 

12-cp monthly system peak for IS 

Network Transmission Service. The 

provisional rate formula is to be 

effective beginning October 1, 2005, 

through September 30, 2010. 

Firm Point-to-Point 

The current IS Firm Point-to-Point 

Transmission Service rate for 2004–

2005 is $2.72 and expires September 30, 

2005. The provisional formula rate will 

continue to be the Annual Revenue 

Requirement for IS Transmission 

Service divided by the IS Transmission 

System Total Load. The provisional rate 

for IS Firm Point-to-Point Transmission 

Service is $2.69 per kWmonth for 2004–

2005. 

Non-Firm Point-to-Point 

The current IS Non-Firm 

Transmission Service rate expires 

September 30, 2005. The provisional 

rate for IS Non-Firm Transmission 

Service is expressed in mills/kWh and 

is based on the current IS Firm Pointto-Point Transmission Service rate and 

may be discounted. The provisional IS 

Non-Firm Point-to-Point Transmission 

Service rate will be the IS Firm Pointto-Point Transmission Service rate 

divided by 730 hours per month and 

multiplied by 1000 mills per dollar. The 

provisional IS Non-Firm Transmission 

Service rate for 2004–2005 is 3.68 mills/ 

kWh. 

The following table summarizes the 

difference in calculations between the 

current IS Transmission Service rates 

and the provisional IS Transmission 

Service rates. It compares the change in 

the average annual projections used in 

the 2004–2005 transmission and 

ancillary services study and the 

provisional IS Transmission Service 

rates for this rate adjustment based upon 

the most recent historical data available 

at the time of the initial rate proposal. 

COMPARISON OF ANNUAL REVENUES

Item Existing rate Provisional rate Percent 

change 

Annual IS Costs ....................................................................................................................... $137,088,496 $136,289,145 ¥0.577 

Transmission Customer Facility Credits .................................................................................. 2,482,447 2,482,647 0.000 

Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices 55829 

COMPARISON OF ANNUAL REVENUES—Continued 

Item Existing rate Provisional rate Percent 

change 

Transmission Revenue Credits ............................................................................................... 9,454,494 9,454,494 0.000 

Annual Revenue Requirement for IS Transmission Service ................................................... 128,017,923 126,741,576 ¥0.997 

The change in annual revenue 

requirement for IS Transmission Service 

is primarily a result of a revision in the 

allocation of expenses and investments. 

The revenue change between the 

existing rate and the provisional rate is 

<1 percent and, therefore, this is a 

minor rate adjustment. 

Basis for Rate Development 

The existing rates for IS Network, 

Firm and Non-Firm Transmission 

Service in Rate Schedules UGP–NT1, 

UGP–FPT1, and UGP–NFPT1, expire 

September 30, 2005. This rate 

adjustment contains rates that replace 

existing rates. The adjusted rates reflect 

changes in costs. The provisional rates 

will provide sufficient revenue to pay 

all annual costs, including interest 

expense, and repay investment within 

the allowable period. The provisional IS 

Transmission Service rates, detailed in 

Rate Schedules UGP–NT1, UGP–FPT1, 

and UGP–NFPT1, will take effect on 

October 1, 2005 to correspond with the 

start of the Federal fiscal year and 

remain in effect through September 30, 

2010, or until replaced. 

The proposed rates for IS 

Transmission Service include a 

provision to pass through electric 

industry restructuring costs associated 

with providing transmission service. 

These costs will be passed through to 

each appropriate IS Transmission 

Customer. 

Comments 

Western did not receive any 

comments or responses regarding the IS 

Transmission Service rate adjustment. 

Ancillary Services Discussion 

The IS will continue to offer six 

ancillary services. These are (1) 

Scheduling, system control, and 

dispatch service, (2) reactive supply and 

voltage control service, (3) regulation 

and frequency response service, (4) 

energy imbalance service, (5) spinning 

reserve service, and (6) supplemental 

reserve service. The first two are 

required services: (1) Scheduling, 

system control, and dispatch service 

and (2) reactive supply and voltage 

control service. All these ancillary 

services are listed in Western’s Tariff. 

The provisional rates for ancillary 

services are designed to recover only the 

costs associated with providing the 

service(s). The formula for calculating 

the rates will remain the same but the 

GSUs will be included in the 

investment and costs for the generation 

fixed charge in support of ancillary 

services. The costs for providing 

Scheduling, System Control, and 

Dispatch Service are included in the 

provisional IS Transmission Service 

rates. 

The following table summarizes the 

difference in calculations between the 

current IS Ancillary Service rates and 

the provisional IS Ancillary Service 

rates. It compares the change in the 

average annual projections used in the 

2004–2005 transmission and ancillary 

services study and the provisional IS 

Transmission and Ancillary Service 

rates for this rate adjustment based upon 

the most recent historical data available 

at the time of the initial rate proposal. 

COMPARISON OF ANCILLARY SERVICE RATES

Item Unit Existing rate Provisional 

rate 

Percent 

change 

Scheduling, System Control and Dispatch Service ................................. schedule/day ......... $49.29 $49.77 0.974 

Reactive Supply and Voltage Control ...................................................... kWmonth ............... 0.06 0.07 16.667

Regulation and Frequency Response ...................................................... kWmonth ............... 0.04 0.04 0.000 

Energy Imbalance .................................................................................... n/a ......................... n/a n/a n/a 

Reserves .................................................................................................. kWmonth ............... 0.11 0.12 9.091 

Basis for Rate Development 

The existing rates for IS Ancillary 

Services in Rate Schedules UGP–AS1, 

UGP–AS2, UGP–AS3, UGP–AS4, UGP–

AS5, and UGP–AS6, expire September 

30, 2005. The rate adjustment contains 

rates that replace existing rates. The 

adjusted rates reflect a revised 

methodology and changes in costs. The 

provisional rates will provide sufficient 

revenue to pay all annual costs, 

including interest expense, and 

repayment of required power 

investment within the allowable period. 

The provisional rates will take effect on 

October 1, 2005, to correspond with the 

start of the Federal fiscal year and 

remain in effect through September 30, 

2010. 

Comments 

Western did not receive any 

comments or responses regarding the IS 

Ancillary Services rate adjustment. 

Availability of Information 

Information about this rate 

adjustment, including studies, 

brochures, comments, letters, 

memorandums, and other supporting 

material made or kept by Western, used 

to develop the provisional rates, is 

available for public review in the Upper 

Great Plains Regional Office, 2900 4th 

Avenue North, Billings, Montana. 

Regulatory Procedure Requirements 

Regulatory Flexibility Analysis 

The Regulatory Flexibility Act of 1980 

(5 U.S.C. 601, et seq.) requires Federal 

agencies to perform a regulatory 

flexibility analysis if a final rule is likely 

to have a significant economic impact 

on a substantial number of small entities 

and there is a legal requirement to issue 

a general notice of proposed 

rulemaking. Western has determined 

that this action does not require a 

regulatory flexibility analysis since it is 

a rulemaking of particular applicability 

involving rates or services applicable to 

public property. 

55830 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices 

Environmental Compliance 

In compliance with the National 

Environmental Policy Act (NEPA) of 

1969 (42 U.S.C. 4321, et seq.); Council 

on Environmental Quality Regulations 

(40 CFR parts 1500–1508); and DOE 

NEPA Regulations (10 CFR part 1021), 

Western has determined that this action 

is categorically excluded from preparing 

an environmental assessment or an 

environmental impact statement. 

Determination Under Executive Order 

12866 

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. 

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. 

Submission to the Federal Energy 

Regulatory Commission 

The interim rates herein confirmed, 

approved, and placed into effect, 

together with supporting documents, 

will be submitted to the Commission for 

confirmation and final approval. 

Order 

In view of the foregoing and under the 

authority delegated to me, I confirm and 

approve on an interim basis, effective 

October 1, 2005, formula rates for the IS 

Transmission and Ancillary Services 

under Rate Schedules UGP–FPT1, UGP–

NFPT1, UGP–NT1, UGP–AS1, UGP–

AS2, UGP–AS3, UGP–AS4, UGP–AS5, 

and UGP–AS6. The rate schedules shall 

remain in effect on an interim basis, 

pending the Commission’s confirmation 

and approval of them or substitute rates 

on a final basis through September 30, 

2010. 

Dated: September 13, 2005. 

Clay Sell, 

Deputy Secretary. 

Rate Schedule UGP–AS1; October 1, 2005; 

Supersedes 1998 Schedule 

Upper Great Plains Region Integrated 

System: Scheduling, System Control, 

and Dispatch Service 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2005, through September 30, 2010, or 

until superseded by another rate 

schedule. 

Applicable 

This service is required to schedule 

the movement of power through, out of, 

within, or into the Western Area Upper 

Great Plains Balancing Authority 

(WAUGP). The charges for Scheduling, 

System Control, and Dispatch Service 

are to be based on the rate outlined 

below. The formula rate used to 

calculate the charges for service under 

this schedule was developed and may 

be modified under applicable Federal 

laws, regulations, and policies. 

The rate will be applied to all 

schedules for WAUGP nonTransmission Customers. The WAUGP 

will accept any reasonable number of 

schedule changes over the course of the 

day without any additional charge. 

The charges for Scheduling, System 

Control, and Dispatch Service may be 

modified upon written notice to the 

customer. Any change to the charges for 

the Scheduling, System Control, and 

Dispatch Service shall be as set forth in 

a revision to this rate schedule 

developed under applicable Federal 

laws, regulations, and policies and 

made part of the applicable 

Transmission Customer’s Service 

Agreement. 

The Upper Great Plains Region 

(UGPR) shall charge the nonTransmission Customer under the rate 

then in effect. 

Formula Rate 

Rate per Schedule per Day = Annual Revenue Requirement for Scheduling, System Control, and Dispatch Service

Number of Daily Schedules per Year

Rate 

A recalculated rate will go into effect 

every May 1 based on the above formula 

and data. The UGPR will notify the 

customer annually of the recalculated 

rate on or before April 1. 

Rate Schedule UGP–AS2; October 1, 2005; 

Supersedes 1998 Schedule 

Upper Great Plains Region Integrated 

System: Reactive Supply and Voltage 

Control From Generation Sources 

Service 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2005, through September 30, 2010, or 

until superseded by another rate 

schedule. 

Applicable 

To maintain transmission voltages on 

all transmission facilities within 

acceptable limits, generation facilities 

under the control of the Western Area 

Upper Great Plains balancing authority 

(WAUGP) are operated to produce or 

absorb reactive power. Thus, Reactive 

Supply and Voltage Control from 

Generation Sources Service (Reactive 

Service) must be provided for each 

transaction on the transmission 

facilities. The amount of Reactive 

Service that must be supplied with 

respect to the Transmission Customer’s 

transaction will be determined based on 

the Reactive Service necessary to 

maintain transmission voltages within 

limits that are generally accepted in the 

region and consistently adhered to by 

WAUGP. 

The Transmission Customer must 

purchase this service from the 

Transmission Provider. The charges for 

such service will be based upon the rate 

outlined below. The formula rate used 

to calculate the charges for service 

under this schedule was developed and 

may be modified under applicable 

Federal laws, regulations, and policies. 

The charges for Reactive Service may 

be modified upon written notice to the 

Transmission Customer. Any change to 

the charges for Reactive Service shall be 

as set forth in a revision to this rate 

schedule developed under applicable 

Federal laws, regulations, and policies 

and made part of the applicable 

Transmission Customer’s Service 

Agreement. The Upper Great Plains 

Region (UGPR) shall charge the 

Transmission Customer under the rate 

then in effect. 

Those Transmission Customers with 

generators in the balancing authority 

providing WAUGP with adequate 


EN23SE05.060</MATH>
Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices 55831 

Reactive Service will not be charged for 

this service. Any waiver of this charge 

or any crediting arrangements for 

Reactive Service must be documented in 

the Transmission Customer’s Service 

Agreement. 

Formula Rate 

Formula Rate 

WAUGP

Reactive Service Annual Revenue Requirement for

Rate = Reactive Service

Load Requiring Reactive Service

Rate 

A recalculated rate will go into effect 

every May 1 based on the above formula 

and updated financial and load data. 

The UGPR will notify the Transmission 

Customer annually of the recalculated 

rate on or before April 1. 

Rate Schedule UGP–AS3; October 1, 2005; 

Supersedes 1998 Schedule 

Upper Great Plains Region Integrated 

System: Regulation and Frequency 

Response Service 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2005, through September 30, 2010, or 

until superseded by another rate 

schedule. 

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 

60 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 Upper Great Plains 

balancing authority (WAUGP) operator. 

The Transmission Customer must either 

purchase this service from WAUGP or 

make alternative comparable 

arrangements to satisfy its Regulation 

obligation. The charges for Regulation 

are outlined below. The amount of 

Regulation will be set forth in the 

applicable Transmission Customer’s 

Service Agreement. 

The formula rate used to calculate the 

charges for service under this schedule 

was developed and may be modified 

under applicable Federal laws, 

regulations, and policies. 

Charges for Regulation may be 

modified upon written notice to the 

Transmission Customer. Any change to 

the Regulation charges shall be as set 

forth in a revision to this rate schedule 

developed under applicable Federal 

laws, regulations, and policies and 

made part of the applicable 

Transmission Customer’s Service 

Agreement. The Upper Great Plains 

Region (UGPR) shall charge the 

Transmission Customer under the rate 

then in effect. 

Transmission Customers will not be 

charged for this service if they receive 

Regulation from another source, or selfsupply it for their own load. Any waiver 

of this charge or any crediting 

arrangement for Regulation must be 

documented in the Transmission 

Customer’s Service Agreement. 

Formula Rate 

WAUGP

Regulation

Rate

Annual Revenue Requirement for Regula = tion

Load in the Balancing Authority Requiring Regulation

Rate 

A recalculated rate will go into effect 

every May 1 based on the above formula 

and updated financial and load data. 

The UGPR will notify the Transmission 

Customer annually of the recalculated 

rate on or before April 1. 

If resources are not available from a 

WAUGP resource, the UGPR will offer 

to purchase the Regulation and pass 

through the costs, plus an amount for 

administration, to the Transmission 

Customer. 

Rate Schedule UGP–AS4; October 1, 2005; 

Supersedes 1998 Schedule 

Upper Great Plains Region Integrated 

System: Energy Imbalance Service 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2005, through September 30, 2010, or 

until superseded by another rate 

schedule. 

Applicable 

Energy Imbalance Service is provided 

when a difference occurs between 

scheduled and actual delivery of energy 

to a load located within the Western 

Area Upper Great Plains Balancing 

Authority (WAUGP) over a single hour. 

The Transmission Customer must either 

obtain this service from WAUGP or 

make alternative comparable 

arrangements to satisfy its Energy 

Imbalance Service obligation. 

The WAUGP shall establish a 

deviation band of +/¥1.5 percent (with 

a minimum of 2 MW) of the scheduled 

transaction to be applied hourly to any 

energy imbalance that occurs as a result 

of the Transmission Customer’s 

scheduled transaction(s). Deviation 

accounting will be completed monthly 

on an hour-to-hour basis. 

The formula rate used to calculate the 

charges for service under this schedule 

was developed and may be modified 

under applicable Federal laws, 

regulations, and policies. 

The Energy Imbalance Service 

compensation may be modified upon 

written notice to the Transmission 

Customer. Any change to the 

Transmission Customer compensation 

for Energy Imbalance Service shall be as 

set forth in a revision to this schedule 

developed under applicable Federal 

laws, regulations, and policies and 

made part of the applicable 

Transmission Customer’s Service 

Agreement. The Upper Great Plains 

Region (UGPR) shall charge the 

Transmission Customer under the rate 

then in effect. 

Formula Rate 

The UGPR reserves the right to 

implement the following upon 

providing notice to the Transmission 

Customer. 


EN23SE05.061</MATH> EN23SE05.062</MATH>
55832 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices 

For negative excursions (under 

deliveries) outside the bandwidth, the 

WAUGP will assess a penalty charge of 

100 mills/kWh. 

For positive excursions (over 

deliveries) outside the bandwidth, over 

deliveries of energy will be forfeited to 

the balancing authority. 

Rate 

The bandwidth in effect October 1, 

2005, through September 30, 2006, is 3 

percent (+/¥1.5 percent hourly 

deviation). 

Rate Schedule UGP–AS5; October 1, 2005; 

Supersedes 1998 Schedule 

Upper Great Plains Region Integrated 

System: Operating Reserve—Spinning 

Reserve Service 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2005, through September 30, 2010, or 

until superseded by another rate 

schedule. 

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 

Transmission Customer must either 

purchase this service from the Western 

Area Upper Great Plains balancing 

authority (WAUGP) or make alternative 

comparable arrangements to satisfy its 

Reserves obligation. The charges for 

Reserves are outlined below. The 

amount of Reserves will be set forth in 

the applicable Transmission Customer’s 

Service Agreement. 

The formula rate used to calculate the 

charges for service under this schedule 

was promulgated and may be modified 

under applicable Federal laws, 

regulations, and policies. 

The charges for Reserves may be 

modified upon written notice to the 

Transmission Customer. Any change to 

the charges for Reserves shall be as set 

forth in a revision to this rate schedule 

developed pursuant to applicable 

Federal laws, regulations, and policies 

and made part of the applicable 

Transmission Customer’s Service 

Agreement. The Upper Great Plains 

Region (UGPR) shall charge the 

Transmission Customer under the rate 

then in effect. 

Formula Rate 

WAUGP

Regulation

Rate Annual Revenue Requirement for Regul = ation

Load in the Balancing Authority Requiring Regulation

Rate 

A recalculated rate will go into effect 

every May 1 based on the above formula 

and updated financial and load data. 

The UGPR will notify the Transmission 

Customer annually of the recalculated 

rate on or before April 1. 

If resources are not available from a 

WAUGP resource, the UGPR will offer 

to purchase the Reserves and pass 

through the costs, plus an amount for 

administration, to the Transmission 

Customer. 

In the event that Reserves are called 

upon for emergency use, the UGPR will 

assess a charge for energy used at the 

Mid-Continent Area Power Pool Rate for 

emergency energy, presently the greater 

of 30 mills/kWh or the prevailing 

market energy rate in the region. The 

Transmission Customer would be 

responsible for providing transmission 

service to get the Reserves to its 

destination. 

Rate Schedule UGP–AS6; October 1, 2005; 

Supersedes 1998 Schedule 

Upper Great Plains Region Integrated 

System: Operating Reserve—

Supplemental Reserve Service 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2005, through September 30, 2010, or 

until superseded by another rate 

schedule. 

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 Transmission 

Customer must either purchase this 

service from the Western Area Upper 

Great Plains Balancing Authority 

(WAUGP) or make alternative 

comparable arrangements to satisfy its 

Reserves obligation. The charges for 

Reserves are outlined below. The 

amount of Reserves will be set forth in 

the applicable Transmission Customer’s 

Service Agreement. 

The formula rate used to calculate the 

charges for service under this schedule 

was developed and may be modified 

under applicable Federal laws, 

regulations, and policies. 

The charges for Reserves may be 

modified upon written notice to the 

Transmission Customer. Any change to 

the charges for Reserves shall be as set 

forth in a revision to this rate schedule 

developed under applicable Federal 

laws, regulations, and policies and 

made part of the applicable Service 

Agreement. The Upper Great Plains 

Region (UGPR) shall charge the 

Transmission Customer under the rate 

then in effect. 

Formula Rate 

WAUGP

Reserves

Rate Annual Revenue Requirement for Reserve = s

Load Requiring Reserves

Rate 

A recalculated rate will go into effect 

every May 1 based on the above formula 

and updated financial and load data. 

The UGPR will notify the Transmission 

Customer annually of the recalculated 

rate on or before April 1. 

If resources are not available from a 

WAUGP resource, the UGPR will offer 

to purchase the Reserves and pass 

through the costs, plus an amount for 

administration, to the Transmission 

Customer. 

In the event Reserves are called upon 

for Emergency Energy, the UGPR will 


EN23SE05.063</MATH> EN23SE05.064</MATH>
Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices 55833 

assess a charge for energy used at the 

Mid-Continent Area Power Pool Rate for 

Emergency Energy, presently the greater 

of 30 mills/kWh or the prevailing 

market energy rate in the region. The 

Transmission Customer would be 

responsible for providing transmission 

service to get the Reserves to its 

destination. 

Rate Schedule UGP–FPT1; October 1, 2005; 

Supersedes 1998 Schedule 

Upper Great Plains Region Integrated 

System: Long-Term Firm and ShortTerm Firm Point-to-Point Transmission 

Service 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2005, through September 30, 2010, or 

until superseded by another rate 

schedule. 

Applicable 

The Transmission Customer shall 

compensate the Upper Great Plains 

Region (UGPR) 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 developed and may be modified 

under applicable Federal laws, 

regulations, and policies. 

The UGPR may modify the rate for 

Firm Point-to-Point Transmission 

Service upon written notice to the 

Transmission Customer. Any change to 

the rate for Firm Point-to-Point 

Transmission Service shall be as set 

forth in a revision to this rate schedule 

developed under applicable Federal 

laws, regulations, and policies and 

made part of the applicable 

Transmission Customer’s Service 

Agreement. The UGPR 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 the UGPR must be announced 

to all eligible Transmission Customers 

solely by posting on the Open Access 

Same-Time Information System 

(OASIS), (2) any Transmission 

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, the UGPR must 

offer the same discounted transmission 

service rate for the same time period to 

all eligible Transmission Customers on 

all unconstrained transmission paths 

that go to the same point(s) of delivery 

on the Transmission System. 

Formula Rate 

Firm Point-to-Point

Transmission Rate = Annual IS Transmission Service Revenue Requirement

IS Transmission System Total Load

Rate 

A recalculated rate will go into effect 

every May 1 based on the above formula 

and updated financial and load data. 

The UGPR will notify the Transmission 

Customer annually of the recalculated 

rate on or before April 1. 

Rate Schedule UGP–NFPT1; October 1, 

2005; Supersedes 1998 Schedule 

Upper Great Plains Region Integrated 

System: Non-Firm Point-to-Point 

Transmission Service 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2005, through September 30, 2010, or 

until superseded by another rate 

schedule. 

Applicable 

The Transmission Customer shall 

compensate the Upper Great Plains 

Region (UGPR) for Non-Firm Point-toPoint Transmission Service under the 

applicable Non-Firm Point-to-Point 

Transmission Service Agreement and 

rate outlined below. The formula rates 

used to calculate the charges for service 

under this schedule were developed and 

may be modified under applicable 

Federal laws, regulations, and policies. 

The UGPR may modify the rate for 

Non-Firm Point-to-Point Transmission 

Service upon written notice to the 

Transmission Customer. Any change to 

the rate for Non-Firm Point-to-Point 

Transmission Service shall be as set 

forth in a revision to this rate schedule 

developed under applicable Federal 

laws, regulations, and policies and 

made part of the applicable 

Transmission Customer’s Service 

Agreement. The UGPR 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 the UGPR must be announced 

to all eligible Transmission Customers 

solely by posting on the Open Access 

Same-Time Information System 

(OASIS), (2) any Transmission 

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, the UGPR must 

offer the same discounted transmission 

service rate for the same time period to 

all eligible Transmission Customers on 

all unconstrained transmission paths 

that go to the same point(s) of delivery 

on the Transmission System. 

Formula Rate 

Maximum Non-Firm

Point-to-Point

Transmission Rate Firm Poi = nt-to-Point

Transmission Rate 730 hoursper month 1000 ÷ × millsper dollar


EN23SE05.065</MATH> EN23SE05.066</MATH>
55834 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices 

Rate 

A recalculated rate will go into effect 

every May 1 based on the above formula 

and updated financial and load data. 

The UGPR will notify the Transmission 

Customer annually of the recalculated 

rate on or before April 1. 

Rate Schedule UGP–NT1; October 1, 2005; 

Supersedes 1998 Schedule 

Upper Great Plains Region Integrated 

System: Annual Transmission Revenue 

Requirement for Network Integration 

Transmission Service 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2005, through September 30, 2010, or 

until superseded by another rate 

schedule. 

Applicable 

The Transmission Customer shall 

compensate the Upper Great Plains 

Region (UGPR) each month for Network 

Transmission Service under the 

applicable Network Integration 

Transmission Service Agreement and 

annual revenue requirement outlined 

below. The formula for the annual 

revenue requirement used to calculate 

the charges for this service under this 

schedule was developed and may be 

modified under applicable Federal laws, 

regulations, and policies. 

The UGPR may modify the charges for 

Network Integration Transmission 

Service upon written notice to the 

Transmission Customer. Any change to 

the charges to the Transmission 

Customer for Network Integration 

Transmission Service shall be as set 

forth in a revision to this rate schedule 

promulgated developed under 

applicable Federal laws, regulations, 

and policies and made part of the 

applicable Transmission Customer’s 

Service Agreement. The UGPR shall 

charge the Transmission Customer 

under the revenue requirement then in 

effect. 

Formula Rate 

Monthly Transmission Charge Customer’s Load-Ratio Share = ( Revenue Requirment for IS Transmission Service) × Annual

12 months

Annual Revenue Requirement 

A recalculated annual revenue 

requirement will go into effect every 

May 1 based on updated financial data. 

The UGPR will notify the Transmission 

Customer annually of the recalculated 

annual revenue requirement on or 

before April 1. 

[FR Doc. 05–19039 Filed 9–22–05; 8:45 am] 

BILLING CODE 6450–01–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

[ER–FRL–6667–7] 

Environmental Impact Statements and 

Regulations; Availability of EPA 

Comments 

Availability of EPA comments 

prepared pursuant to the Environmental 

Review Process (ERP), under section 

309 of the Clean Air Act and Section 

102(2)(c) of the National Environmental 

Policy Act as amended. Requests for 

copies of EPA comments can be directed 

to the Office of Federal Activities at 

202–564–7167. An explanation of the 

ratings assigned to draft environmental 

impact statements (EISs) was published 

in the Federal Register dated April 1, 

2005 (70 FR 16815). 

Draft EISs 

EIS No. 20050187, ERP No. D–SFW–

F64005–00, Upper Mississippi 

National Wildlife and Fish Refuge 

Comprehensive Conservation Plan 

(CCP) Implementation, MN, WI, IL 

and IA. 

Summary: EPA has no objections to 

the Preferred Alternative, and 

recommends that the Final EIS address 

how the plan will be integrated with the 

Upper Mississippi River Navigation 

Ecosystem Sustainability Program. 

Rating LO. 

EIS No. 20050209, ERP No. D–NPS–

J65442–WY, Grand Teton National 

Park Transportation Plan, 

Implementation, Grand Teton 

National Park, Teton County, WY. 

Summart: EPA expressed concerns 

about wetland mitigation and storm 

water impacts. Rating EC2. 

EIS No. 20050259, ERP No. D–FHW–

C40166–NY, Southtowns Connector/ 

Buffalo Outer Harbor Project, 

Improvements on the NYS Route 5 

Corridor from Buffalo Skyway Bridge 

to NYS Route 179, in the City of 

Buffalo, City of Lackawanna and 

Town of Hamburg, Erie County, NY. 

Summary: EPA expressed concerns 

about assessment of cumulative 

impacts. Rating EC2. 

EIS No. 20050274, ERP No. D–AFS–

J61107–ND, NE McKenzie Allotment 

Management Plan Revisions, Proposes 

to Continue Livestock Grazing on 28 

Allotments, Dakota Prairie Grasslands 

Land and Resource Management Plan, 

Dakota Prairie Grasslands, McKenzie 

Ranger District, McKenzie County, 

ND. 

Summary: EPA expressed concerns 

about potential water quality impacts 

from sediment, fecal coliform and 

temperature modification in streams 

and other surface waters, and 

recommended reducing water quality 

impacts near aquatic/riparian resources 

by working with permittees and other 

stakeholders, and develop adaptive 

management monitoring. Rating EC2. 

EIS No. 20050281, ERP No. D–AFS–

K65287–CA, North Fork Eel Grazing 

Allotment Management Project, 

Proposing to Authorize Cattle Grazing 

on Four Allotment, Six Rivers 

National Forest, Mad River Ranger 

District, North Fork Eel River and 

Upper Mad River, Trinity County, CA. 

Summary: EPA has no objection to the 

proposed action. Rating LO. 

EIS No. 20050306, ERP No. D–FHW–

H40185–00, U.S. Highway 34, 

Plattsmouth Bridge Study, over the 

Missouri River between U.S. 75 and I–

29, Funding, Coast Guard Permit, U.S. 

Army COE 10 and 404 Permits, Cass 

County, NE and Mills County, IA. 

Summary: EPA expressed concerns 

about potential wetland, floodplain, 

stream, and cumulative impacts. Rating 

EC2. 

EIS No. 20050311, ERP No. D–NPS–

H65025–NE, Niobrara National Scenic 

River General Management Plan, 

Implementation, Brown, Cherry, Keya 

Paha and Rock Counties, NE. 

Summary: EPA has no objection to the 

proposed action. Rating LO. 

EIS No. 20050294, ERP No. DR–COE–

K11114–CA, Mare Island Reuse of 

Dredged Material Disposal Ponds as a 

Confirmed Updated Dredged Material 

Disposal Facility, Issuing Section 404 

Permit Clean Water Act and Section 

10 Permit Rivers and Harbor Act, San 

Francisco Bay Area, City of Vallejo, 

Solando County, CA. 

Summary: Many of EPA’s objections 

to the original Draft EIS were addressed 

in this revised document. However, EPA 

continues to have concerns about the 

delegation of responsibility for site 

operations and associated 

environmental safeguards, as well as 

implementation of wetlands restoration 

measures. Rating EC2.FINAL EISs. 


EN23SE05.067</MATH>