26682 Federal Register / Vol. 74, No. 105 / Wednesday, June 3, 2009 / Notices 

1Western’s OATT was most recently approved by 

FERC in Docket No. NJ07–2–000, 119 FERC 61,329 

(2007) and the FERC’s delegated order issued on 

September 6, 2007, in Docket No. NJ07–2–001. 

2Rate Order No. WAPA–122, 70 FR 55821, 

September 23, 2005, and the FERC confirmed and 

approved the rate schedules on May 30, 2006, 

under FERC Docket No. EF05–5031–000, 115 FERC 

62,230. 

Docket No. ER09–262, Southwest Power 

Pool, Inc. 

Docket No. ER09–336, Southwest Power 

Pool, Inc. 

Docket No. ER09–342, Southwest Power 

Pool, Inc. 

Docket No. ER09–443, Southwest Power 

Pool, Inc. 

Docket No. ER09–659, Southwest Power 

Pool, Inc. 

Docket No. ER09–748, Southwest Power 

Pool, Inc. 

Docket No. ER09–883, Southwest Power 

Pool, Inc. 

Docket No. ER09–1039, Southwest 

Power Pool, Inc. 

Docket No. ER09–1042, Southwest 

Power Pool, Inc. 

Docket No. ER09–1055, Southwest 

Power Pool, Inc. 

Docket No. ER09–1056, Southwest 

Power Pool, Inc. 

Docket No. ER09–1057, Southwest 

Power Pool, Inc. 

Docket No. ER09–1068, Southwest 

Power Pool, Inc. 

Docket No. ER09–1080, Southwest 

Power Pool, Inc. 

Docket No. ER09–1130, Southwest 

Power Pool, Inc. 

Docket No. ER09–1140, Southwest 

Power Pool, Inc. 

Docket No. ER09–1152, Southwest 

Power Pool, Inc. 

Docket No. ER09–1172, Southwest 

Power Pool, Inc. 

Docket No. ER09–1174, Southwest 

Power Pool, Inc. 

Docket No. ER09–1177, Southwest 

Power Pool, Inc. 

Docket No. ER09–1192, Southwest 

Power Pool, Inc. 

Docket No. OA08–5 and EL09–40, 

Southwest Power Pool, Inc. 

Docket No. OA08–60, Southwest Power 

Pool, Inc. 

Docket No. OA08–61, Southwest Power 

Pool, Inc. 

Docket No. OA08–104, Southwest Power 

Pool, Inc. 

These meetings are open to the 

public. 

For more information, contact Patrick 

Clarey, Office of Energy Market 

Regulation, Federal Energy Regulatory 

Commission at (317) 249–5937 or 

patrick.clarey@ferc.gov. 

Kimberly D. Bose, 

Secretary. 

[FR Doc. E9–12867 Filed 6–2–09; 8:45 am] 

BILLING CODE 6717–01–P 

DEPARTMENT OF ENERGY 

Western Area Power Administration 

Pick-Sloan Missouri Basin Program— 

Eastern Division-Rate Order No. 

WAPA–144 

AGENCY: Western Area Power 

Administration, DOE. 

ACTION: Notice of Proposed 

Transmission and Ancillary Services 

Rates. 

SUMMARY: The Western Area Power 

Administration (Western) is proposing 

to update its rates for transmission and 

ancillary services for the Pick-Sloan 

Missouri Basin Program—Eastern 

Division (P-SMBP—ED). Current 

formula rates, under Rate Schedules 

UGP–NT1, UGP–FPT1, UGP–NFPT1, 

UGP–AS1, UGP–AS2, UGP–AS3, UGP– 

AS4, UGP–AS5, and UGP–AS6 will 

expire on September 30, 2010. Western 

is also proposing to add a new rate 

schedule, Rate Schedule UGP–AS7, for 

Generator Imbalance Service. Western is 

proposing these rates to meet evolving 

and expanding transmission system and 

ancillary services requirements. Western 

will prepare a brochure that provides 

detailed information on the proposed 

rates to all interested parties. The 

proposed rates, under Rate Schedules 

UGP–NT1, UGP–FPT1, UGP–NFPT1, 

UGP–AS1, UGP–AS2, UGP–AS3, UGP– 

AS4, UGP–AS5, and UGP–AS6, are 

scheduled to go into effect on January 1, 

2010, and will remain in effect through 

December 31, 2014, or until superseded. 

The new rate schedule for Generator 

Imbalance Service, under Rate Schedule 

UGP–AS7, is scheduled to go into effect 

on the latter of January 1, 2010, or when 

Western’s Open Access Transmission 

Tariff (OATT) is revised to provide for 

Generator Imbalance Service. If 

implemented, Rate Schedule UGP–AS7 

will also remain in effect through 

December 31, 2014, or until superseded, 

to coincide with the other ancillary 

service rates in this rate order. 

Publication of this Federal Register 

notice begins the formal process for the 

proposed formula rates. 

DATES: The consultation and comment 

period begins today and will end 

October 1, 2009. Western will present a 

detailed explanation of the proposed 

formula rates at a public information 

forum. The public information forum 

date is June 24, 2009, 9 a.m. to 12 p.m. 

CDT, Sioux Falls, South Dakota. 

Western will accept oral and written 

comments at a public comment forum. 

The public comment forum date is July 

28, 2009, 9 a.m. to 12 p.m. CDT, Sioux 

Falls, South Dakota. Western will accept 

written comments any time during the 

consultation and comment period. 

ADDRESSES: Written comments and/or 

requests to be informed of Federal 

Energy Regulatory Commission (FERC) 

actions concerning the rates submitted 

by Western to the FERC for approval 

should be sent to Robert J. Harris, 

Regional Manager, Upper Great Plains 

Region, Western Area Power 

Administration, 2900 4th Avenue North, 

Billings, MT 59101–1266, e-mail 

UGPISRate@wapa.gov. Western will 

post information about the rate process 

on its Web site at http://www.wapa.gov/ 

ugp/rates/default.htm. Western will 

post official comments received via 

letter and e-mail to its Web site after the 

close of the comment period. Western 

must receive written comments by the 

end of the consultation and comment 

period to ensure they are considered in 

Western’s decision process. The public 

information forum location is the 

Holiday Inn, 100 West 8th Street, Sioux 

Falls, SD. The public comment forum 

location is the Holiday Inn, 100 West 

8th Street, Sioux Falls, SD. 

FOR FURTHER INFORMATION CONTACT: Ms. 

Linda Cady-Hoffman, Rates Manager, 

Upper Great Plains Region, Western 

Area Power Administration, 2900 4th 

Avenue North, Billings, MT 59101– 

1266, telephone (406) 247–7439, e-mail 

cady@wapa.gov. 

SUPPLEMENTARY INFORMATION: The 

transmission facilities in the P–SMBP— 

ED are integrated with transmission 

facilities of Basin Electric Power 

Cooperative (Basin) and Heartland 

Consumers Power District (Heartland) 

such that transmission services are 

provided over an integrated 

transmission system, called the 

Integrated System (IS), and the rates are 

sometimes referred to as IS Rates. 

Western acts as the administrator of the 

IS and monitors service under the 

OATT.1 As owners of the IS, Western, 

Basin, and Heartland may be referred to 

as IS Partners. The Deputy Secretary of 

Energy approved the current Rate 

Schedules UGP–FPT1, UGP–NFPT1, 

UGP–NT1, UGP–AS1, UGP–AS2, UGP– 

AS3, UGP–AS4, UGP–AS5, and UGP– 

AS6 for P–SMBP—ED firm and non-firm 

transmission rates and ancillary services 

rates through September 30, 2010.2 The 

current rate schedules contain formulabased rates that are recalculated 


PWALKER on PROD1PC71 with NOTICES
Federal Register / Vol. 74, No. 105 / Wednesday, June 3, 2009 / Notices 26683 

annually. The proposed rates continue 

the formula-based approach and will be 

recalculated annually from financial 

and load information. Western intends 

for the proposed formula-based rates to 

go into effect January 1, 2010, and 

remain in effect through December 31, 

2014. Annual recalculated rates are 

proposed go into effect on January 1, 

2011, and annually on January 1 

thereafter. 

Proposed Change to Forward-Looking 

Formula Transmission Rates 

Western proposes to change the 

implementation of the formula rates to 

recover transmission expenses and 

investments on a current (forwardlooking), rather than a lagging basis. 

This will allow Western to more 

accurately match cost recovery with cost 

incurrence. Western will use projections 

to estimate transmission costs and load 

for the upcoming year in the annual 

recalculation of the Annual 

Transmission Revenue Requirement 

(ATRR). Western will ‘‘true-up’’ the cost 

estimates with Western’s actual costs. 

This is a change in the manner in which 

the inputs for the revenue requirement 

are currently developed, rather than a 

change to the formula rate itself. Rates 

will continue to be recalculated every 

year. Revenue collected in excess of 

Western’s actual net revenue 

requirement will be returned to 

customers through a credit against rates 

in a subsequent year. Actual revenues 

that are less than the net revenue 

requirement would likewise be 

recovered in a subsequent year. The 

true-up procedure would ensure that 

Western will recover no more and no 

less than the actual transmission costs 

for the year. For example, at the end of 

2010, and as actual year-end financial 

data becomes available during 2011, the 

under or over collection of revenue 

during 2010 will be determined. When 

the rates are recalculated for 

implementation on January 1, 2012, the 

implemented rates will include an 

adjustment for revenue over or under 

collected in 2010. 

Proposed Implementation of 

Transmission and Ancillary Services 

Rates on January 1 

With the implementation of the 

applicable rates (resulting from this 

process) effective on January 1, 2010, 

Western proposes to change the date of 

the annual implementation of the 

recalculated rates for each applicable 

rate schedule to January 1, 2011, and 

January 1 of each year thereafter. In the 

past, annual implementation of the 

recalculation of the formula rates was 

effective annually on May 1. With the 

implementation date change from May 1 

to January 1, the data used in the rate 

recalculation for the rates that will be 

effective on January 1will be made 

available for review and comment on or 

shortly after September 1 each year. 

Western proposes providing customers 

the opportunity to discuss and comment 

on the recalculated rates on or before 

October 31, 2010, and October 31 of 

subsequent years. This procedure will 

ensure that the data is available, 

interested parties are aware of the data 

used to calculate the rates, and will 

provide interested parties the 

opportunity to comment before the costs 

are collected through the formula rate. 

Proposed Use of Revenue Requirement 

Calculation Templates 

Western proposes to initiate the use of 

standard revenue requirement 

calculation templates for the annual rate 

recalculation to aid in the revenue 

requirement/rate recalculation and 

review processes. The revenue 

requirement templates will provide a 

standard format to gather and record 

required financial information from 

Western, Basin, Heartland, and 

Transmission Customers receiving 

facilities credits for facilities integrated 

with the IS. Entities submitting financial 

data may request the use of other or 

modified templates. However, once 

accepted, consistent use of the accepted 

template will be required for subsequent 

financial data submission for that entity. 

Western will review future requests to 

utilize other or modified templates for 

appropriateness and conduct a public 

process prior to granting approval for 

use. 

Proposed Formula Rate for Network 

Transmission Service 

The formula for calculating the 

Network Transmission Service rate is 

unchanged from Western’s previously 

approved filing with the FERC. The 

change to a current year formula rate 

involves a change to the manner in 

which the inputs are developed rather 

than a change in the formula rate itself. 

The same ATRR is used for both 

network and point-to-point rates. The 

current methodology for determining 

the customers’ charges for monthly 

Network IS Transmission Service is the 

product of the network customer’s load 

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, and depreciation. The annual 

costs are reduced by revenue credits for 

the Non-Firm Transmission Service. 

The load ratio share is based upon the 

network customer’s hourly load 

coincident with the IS monthly 

transmission system peak minus the 

coincident peak for all IS Firm Point-toPoint Transmission Service plus the 

point-to-point reservations. The 

Network Transmission Service rate 

includes costs for Scheduling, System 

Control, and Dispatch (SSCD) Service 

needed to provide transmission service. 

A revenue requirement template will be 

used to calculate the ATRR utilizing the 

costs estimates as data inputs. 

Proposed Formula Rate for Firm Pointto-Point IS Transmission Service 

Western proposes no change in the 

rate formula for Firm Point-to-Point IS 

Transmission Service other than 

utilizing transmission cost projections 

as data inputs in the determination of 

the annual revenue requirement as 

described above. The proposed Firm 

Point-to-Point IS Transmission Service 

rate remains the annual revenue 

requirement required for IS 

transmission service less the non-firm 

revenue credits all divided by annual 

average transmission system monthly 

peak load and then divided again by 12 

months. The Firm Point-to-Point rate 

includes the cost for SSCD Service 

needed to provide transmission service. 

Proposed Formula Rate for Non-Firm 

Point-to-Point Transmission Service 

Western proposes no change in the 

rate formula for Non-Firm Point-to-Point 

Transmission Service other than 

utilizing transmission cost projections 

as data inputs to determine the annual 

revenue requirement as described 

above. The Non-Firm Point-to-Point 

Transmission Service rate formula 

remains the monthly IS Firm Point-toPoint Transmission Service rate divided 

by 730 hours per month times 1000 

mills per dollar. 

Proposed Formula Rate for SSCD 

Service 

Western proposes to continue the 

current formula-based rate methodology 

for SSCD Service, except that the 

formula will divide the annual revenue 

requirement for SSCD Service by the 

number of daily tags in the calculation 

year instead of dividing the annual 

revenue requirement by the number of 

daily schedules in the calculation year. 

This is a terminology change only. 

Schedules and tags have become 

synonymous in Western’s Upper Great 

Plains Region, and therefore, calculating 

the SSCD Service rate with either as the 


PWALKER on PROD1PC71 with NOTICES
26684 Federal Register / Vol. 74, No. 105 / Wednesday, June 3, 2009 / Notices 

3Western has retained the term ‘‘Control Area’’ in 

this document maintaining consistency with usage 

of the term in the FERC’s pro forma tariff and 

Western’s current OATT.* As defined in Western’s 

OATT, a Control Area is: An electric power system 

or combination of electric power systems to which 

a common automatic generation control scheme is 

applied in order to: (1) Match, at all times, the 

power output of the generators within the electric 

system(s) and capacity and energy purchased from 

entities outside the electric power system(s), with 

load within the electric power system(s); (2) 

maintain scheduled interchange with other Control 

Areas, within the limits of Good Utility Practice; (3) 

maintain the frequency of the electric power 

system(s) within reasonable limits in accordance 

with Good Utility Practice; and (4) provide 

sufficient generating capacity to maintain operating 

reserves in accordance with Good Utility Practice. 

denominator will result in the same 

rate. The change of terminology 

provides consistency among Western’s 

regions in describing the formula for 

SSCD Service. 

Proposed Formula Rate for Reactive 

Supply and Voltage Control From 

Generation Sources Service 

Western’s current formula for 

Reactive Supply and Voltage Control 

from Generation Sources (RSVC) 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 five (5) 

year average peak monthly percentage of 

Western’s generation operating in a 

synchronous condenser mode to 

determine Western’s reactive service 

revenue requirement. Western’s, 

Basin’s, Heartland’s, and Missouri River 

Energy Services’ annual costs for 

revenue requirements for RSVC Service 

are summed to get the total revenue 

requirement for this service. The RSVC 

rate is then derived by dividing the total 

annual revenue requirement by the load 

requiring reactive service. The annual 

cost is then divided by 12 months to 

obtain a monthly charge. In this 

formula, Western is only compensated 

for providing RSVC Service based upon 

the cost of Western’s generation 

operating outside the 0.95 leading to 

0.95 lagging power factor bandwidth, 

while Basin, Heartland, and Missouri 

River Energy Services are compensated 

based on costs for generation operating 

within this power factor bandwidth. 

Western is proposing a change to its 

rate for RSVC Service by removing costs 

of any generation associated with 

operation within the bandwidth from 

the total revenue requirement for this 

service. Under Western’s current rate, 

Western is not compensated for 

providing RSVC Service from its own 

generators operating inside the 

bandwidth, while non-Federal 

generators are receiving compensation 

for providing RSVC Service within the 

bandwidth. Western believes that both 

Federal and non-Federal generators 

should be treated comparably when 

they provide RSVC Service within the 

bandwidth. Therefore, Western is 

proposing discontinuing payment for all 

other generators providing RSVC 

Service within the 0.95 leading to 0.95 

lagging power factor bandwidth. 

Western will continue to collect its 

RSVC Service cost, for its generators 

operating within the bandwidth, in the 

firm power revenue requirement under 

the then appropriate firm power rate 

schedule and not from Transmission 

Customers under its OATT. Therefore, 

only Federal preference power 

customers will pay the RSVC costs of 

the Federal generators operating within 

the bandwidth. This change will result 

in transmission service customers 

paying for RSVC Service based only 

upon costs for generators operating 

outside the bandwidth. Excluding RSVC 

Service costs associated with generator 

operation within the bandwidth from 

the RSVC Service revenue requirement 

will require all other non-Federal 

generator owners to recover their RSVC 

Service costs, for operation within the 

bandwidth, elsewhere. 

Western’s Federal generation is 

required to operate in synchronous 

condenser mode (i.e., outside the power 

factor bandwidth) to maintain system 

voltages and meet reliability criteria and 

therefore, consistent with the previous 

practice, Western will include its costs 

to provide RSVC Service for Federal 

generators operating outside the 

bandwidth. Western will also include 

costs associated with other non-Federal 

generators required to operate outside 

the power factor bandwidth to maintain 

system voltages and meet reliability 

criteria (e.g., other generators that 

operate as synchronous condensers, or 

generators that are requested by Western 

to operate outside the bandwidth as 

noted in Western’s generator 

interconnection procedures and 

agreements). 

The following rate formula will apply: 

Western’s total P–SMBP–ED generation 

net plant multiplied by the generation 

fixed charge rate (in percent) provides 

Western’s annual cost. That annual cost 

is multiplied by the five (5) year average 

peak monthly percentage of Western’s 

Federal synchronous condensing 

generation to determine Western’s 

‘‘outside the bandwidth’’ reactive 

service revenue requirement. Western’s 

revenue requirement is then summed 

with any revenue requirement or costs 

incurred from other non-Federal 

generators required by Western to 

operate outside the bandwidth to 

provide the total annual revenue 

requirement for RSVC Service. This 

total annual revenue requirement is 

then divided by the total load (kWyear) 

in Western’s Control Areas.3 The annual 

cost is then divided by 12 months to 

obtain a monthly charge. 

Proposed Formula Rate for Regulation 

and Frequency Response Service 

Western proposes to continue the 

current formula-based rate methodology 

for Regulation and Frequency Response 

Service as described below. 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 generation, both of which are 

United States Army Corps of Engineers 

(Corps) facilities. The Corps’ generation 

fixed charge rate (in percent) is applied 

to Oahe and Fort Peck generation net 

plant investment producing an annual 

Corps generation cost for the Oahe and 

Fort Peck Power plants. This cost is 

divided by the capacity at the plants to 

derive a dollar per kilowatt amount for 

Oahe’s and Fort Peck’s installed 

capacity (kWyear). This dollar per 

kilowatt amount is then applied to the 

capacity of Oahe and Fort Peck 

generation reserved for Regulation and 

Frequency Response Service in the 

Control Area. Western’s 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 

Service and adding cost associated with 

the purchase of power resources to 

provide Regulation and Frequency 

Response Service to support 

intermittent renewable resources as 

described below. The total Regulation 

and Frequency Response Service 

revenue requirement is determined by 

adding the Regulation and Frequency 

Response Revenue Requirement for 

Western, Basin, and Heartland. The 

Regulation and Frequency Response 

Service charge is then determined by 

dividing the total revenue requirement 

by the IS Network Load in the Control 

Area (kWyear). The annual cost is then 

divided by 12 months to obtain a 

monthly charge. 

Western supports the installation of 

renewable sources of energy but 

recognizes that certain operational 

constraints exist in managing the 

significant fluctuations that are a normal 

part of their operation. When Western 

purchases power resources to provide 

Regulation and Frequency Response 

Service to intermittent renewable 

generation resources serving load within 

Western’s Control Areas, costs for these 


PWALKER on PROD1PC71 with NOTICES
Federal Register / Vol. 74, No. 105 / Wednesday, June 3, 2009 / Notices 26685 

regulation resources will become part of 

Western’s Regulation and Frequency 

Response Service charges. However, 

Western has marketed the maximum 

practical amount of power from each of 

its projects, leaving little or no 

flexibility for provision of additional 

power services. Consequently, Western 

will not regulate for the difference 

between the output of an intermittent 

generator located within Western’s 

Control Area and a delivery schedule 

from that generator serving load located 

outside of Western’s Control Area. 

Intermittent generators serving load 

outside Western’s Control Area will be 

required to pseudo-tie or dynamically 

schedule their generation to another 

Control Area. 

An intermittent resource, for the 

limited purpose of these Rate 

Schedules, is an electric generator that 

is not dispatchable and cannot store its 

fuel source and therefore cannot 

respond to changes in system demand 

or respond to transmission security 

constraints. 

Proposed Rate for Energy Imbalance 

Service 

Western proposes to revise its rate for 

Energy Imbalance Service to be 

consistent with rules promulgated by 

FERC to the extent consistent with 

Western’s mission and permitted by law 

and regulations. Currently, penalty 

charges apply only 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 while over 

deliveries outside the bandwidth are 

forfeited. 

Western proposes that charges be 

modified and based on deviation bands 

as follows: 

(i) Deviations within +/¥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 Transmission 

Customer’s scheduled transaction(s) 

will be netted on a monthly basis and 

settled financially, at the end of the 

month, at 100 percent of the average 

incremental cost for the month; 

(ii) Deviations greater than +/¥1.5 

percent up to 7.5 percent (or greater 

than 2 MW up to 10 MW) of the 

scheduled transaction(s) to be applied 

hourly to any energy imbalance that 

occurs as a result of Transmission 

Customer’s scheduled transaction(s) 

will be settled financially, at the end of 

each month, at 110 percent of 

incremental cost when energy taken by 

the Transmission Customer in a 

schedule hour is greater than the energy 

scheduled or 90 percent of incremental 

cost when energy taken by a 

Transmission Customer in a schedule 

hour is less than the scheduled amount; 

and 

(iii) Deviations greater than +/¥7.5 

percent (or 10 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) will be settled 

financially, at the end of each month, at 

125 percent of the highest incremental 

cost that occurs that day for energy 

taken by the Transmission Customer in 

a scheduled hour that is greater than the 

energy scheduled, or 75 percent of the 

lowest incremental cost that occurs that 

day when energy taken by a 

Transmission Customer is less than the 

scheduled amount. 

Western’s incremental cost will be 

based upon a representative hourly 

energy index or combination of indexes. 

The index to be used will be posted on 

Western’s Open Access Same-Time 

Information System (OASIS) http:// 

www.oatioasis.com/wapa/index.html at 

least 30 days prior to use for 

determining the Western incremental 

cost and will not be changed more often 

than once per year unless Western 

determines that the existing index is no 

longer a reliable price index. 

Proposed Formula Rates for Operating 

Reserves Service—Spinning and 

Supplemental 

Western proposes to continue the 

current formula-based rate methodology 

for Spinning Reserve Service and 

Supplemental Reserve Service (Reserve 

Services), except that Western will 

substitute the reserve requirement of the 

current reserve sharing group of which 

Western and the IS Partners are 

members or will substitute Western’s 

and the IS Partners’ own operating 

reserve requirement for the MidContinent Area Power Pool requirement. 

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/kWyear is 

determined by dividing the annual cost 

of generation by the plant capacity. The 

capacity used for Reserve Services is 

determined by multiplying the peak IS 

load by the operating reserve 

requirement of either the current reserve 

sharing group of which Western and the 

IS Partners are members or their own 

operating reserve requirement. The cost/ 

kWyear is multiplied by the capacity 

used for Reserve Services to obtain the 

annual revenue requirement. 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 design recovers 

only Western’s revenue requirement 

associated with Reserve Services. 

Western has no long-term reserves 

available beyond its own internal 

requirements. At a customer’s request, 

Western will acquire needed resources 

and pass the costs on to the requesting 

customer. The customer is responsible 

to provide the transmission to deliver 

these reserves. 

Proposed Rate for Generator Imbalance 

Service 

Western proposes to add a Generator 

Imbalance Service rate in a new rate 

schedule, Rate Schedule UGP–AS7, to 

be consistent with rules promulgated by 

FERC to the extent consistent with 

Western’s mission and permitted by law 

and regulations. However, if Western 

does not also implement a Generator 

Imbalance Service in a revised OATT, 

this rate will not be utilized. 

Generator Imbalance Service is 

provided when a difference occurs 

between the output of a generator 

located within the Transmission 

Provider’s Control Area and a delivery 

schedule from that generator to (1) 

another Control Area or (2) a load 

within the Transmission Provider’s 

Control Area over a single hour. 

Western will offer this service, to the 

extent that it is feasible to do so from 

its own resources or from resources 

available to it, when Transmission 

Service is used to deliver energy from a 

generator located within its Control 

Area. The Transmission Customer must 

either purchase this service from 

Western or make alternative comparable 

arrangements, which may include use of 

non-generation resources capable of 

providing this service, to satisfy its 

Generator Imbalance Service obligation. 

Western may charge a Transmission 

Customer a penalty for either hourly 

generator imbalances under this 

Schedule UGP–AS7 or hourly energy 

imbalances under Rate Schedule UGP– 

AS4 for imbalances occurring during the 

same hour, but not both, unless the 

imbalances aggravate rather than offset 

each other. 

Western supports the installation of 

renewable sources of energy but 

recognizes that certain operational 

constraints exist in managing the 

significant fluctuations that are a normal 

part of their operation. Western has 

marketed the maximum practical 

amount of power from each of its 

projects, leaving little or no flexibility 

for provision of additional power 

services. Consequently, Western will 

not regulate for the difference between 


PWALKER on PROD1PC71 with NOTICES
26686 Federal Register / Vol. 74, No. 105 / Wednesday, June 3, 2009 / Notices 

the output of an intermittent generator 

located within Western’s Control Area 

and a delivery schedule from that 

generator serving load located outside of 

Western’s Control Area. Intermittent 

generators serving load outside 

Western’s Control Area will be required 

to pseudo-tie or dynamically schedule 

their generation to another Control Area. 

An intermittent resource, for the limited 

purpose of these schedules, is an 

electric generator that is not 

dispatchable and cannot store its fuel 

source and therefore cannot respond to 

changes in system demand or respond 

to transmission security constraints. 

Western proposes to base the rate on 

deviation bands as follows: 

(i) Deviations within +/¥1.5 percent 

(with a minimum of 2 MW) of the 

scheduled transaction to be applied 

hourly to any generator imbalance that 

occurs as a result of Transmission 

Customer’s scheduled transaction(s) 

will be netted on a monthly basis and 

settled financially, at the end of the 

month, at 100 percent of the average 

incremental cost; 

(ii) Deviations greater than ±1.5 

percent up to 7.5 percent (or greater 

than 2 MW up to 10 MW) of the 

scheduled transaction to be applied 

hourly to any generator imbalance that 

occurs as a result of Transmission 

Customer’s scheduled transaction(s) 

will be settled financially, at the end of 

each month. When energy delivered in 

a schedule hour from the generation 

resource is less than the energy 

scheduled, the charge is 110 percent of 

incremental cost. When energy 

delivered from the generation resource 

is greater than the scheduled amount, 

the credit is 90 percent of the 

incremental cost; and 

(iii) Deviations greater than ±7.5 

percent (or 10 MW) of the scheduled 

transaction to be applied hourly to any 

generator imbalance that occurs as a 

result of the Transmission Customer’s 

scheduled transaction(s) will be settled 

at 125 percent of Western’s highest 

incremental cost for the day when 

energy delivered in a schedule hour is 

less than the energy scheduled or 75 

percent of Western’s lowest daily 

incremental cost when energy delivered 

from the generation resource is greater 

than the scheduled amount. As an 

exception, an intermittent resource will 

be exempt from this deviation band and 

will pay the deviation band charges for 

all deviations greater than the larger of 

1.5 percent or 2 MW. 

Notwithstanding the foregoing, 

deviations from scheduled transactions 

in order to respond to directives by the 

Transmission Provider, a balancing 

authority, or a reliability coordinator 

shall not be subject to the deviation 

bands identified above and, instead, 

shall be settled financially, at the end of 

the month, at 100 percent of 

incremental cost. Such directives may 

include instructions to correct 

frequency decay, respond to a reserve 

sharing event, or change output to 

relieve congestion. 

Western’s incremental cost will be 

based upon a representative hourly 

energy index or combination of indexes. 

The index to be used will be posted on 

Western’s OASIS http:// 

www.oatioasis.com/wapa/index.html at 

least 30 days prior to use for 

determining the Western incremental 

cost and will not be changed more often 

than once per year unless Western 

determines that the existing index is no 

longer a reliable price index. 

Legal Authority 

Western is proposing transmission 

and ancillary service rates for the P– 

SMBP—ED in accordance with section 

302 of the Department of Energy (DOE) 

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

section transferred to and vested in the 

Secretary of Energy the power marketing 

functions of the Secretary of the 

Department of 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)); and section 5 

of the Flood Control Act of 1944 (16 

U.S.C. 825s); and other acts that 

specifically apply to the projects 

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 FERC. 

Existing DOE procedures for public 

participation in power rate adjustments 

(10 CFR part 903) were published on 

September 18, 1985 (50 FR 37835). 

After review of public comments, and 

possible amendments or adjustments, 

Western will recommend the Deputy 

Secretary of Energy approve the 

proposed rates on an interim basis. 

Availability of Information 

All brochures, studies, comments, 

letters, memorandums, or other 

documents that Western initiates or uses 

to develop the proposed rates are 

available for inspection and copying at 

the Upper Great Plains Regional Office, 

located at 2900 4th Avenue North, 

Billings, Montana. Many of these 

documents and supporting information 

are also available on its Web site under 

the ‘‘2009 Transmission and Ancillary 

Services Rate Adjustment Process’’ 

section located at http://www.wapa.gov/ 

ugp/rates/default.htm. 

Regulatory Procedure Requirements: 

Environmental Compliance 

In compliance with the National 

Environmental Policy Act of 1969 

(NEPA) (42 U.S.C. 4321–4347), Council 

on Environmental Quality Regulations 

(40 CFR parts 1500–1508), and DOE 

NEPA Regulations (10 CFR part 1021), 

Western is in the process of determining 

whether an environmental assessment 

or an environmental impact statement 

should be prepared or if this action can 

be categorically excluded from those 

requirements. 

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. 

Dated: May 15, 2009. 

Timothy J. Meeks, 

Administrator. 

[FR Doc. E9–12920 Filed 6–2–09; 8:45 am] 

BILLING CODE 6450–01–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

[EPA–HQ–SFUND–2009–0078; FRL–8913–3] 

Agency Information Collection 

Activities; Submission to OMB for 

Review and Approval; Comment 

Request; Brownfields Program— 

Revitalization Grantee Reporting 

(Renewal); EPA ICR No. 2104.03, OMB 

Control No. 2050–0192 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Notice. 

SUMMARY: In compliance with the 

Paperwork Reduction Act (PRA) (44 

U.S.C. 3501 et seq.), this document 

announces that an Information 

Collection Request (ICR) has been 

forwarded to the Office of Management 

and Budget (OMB) for review and 

approval. This is a request to renew an 

existing approved collection. The ICR, 

which is abstracted below, describes the 

nature of the information collection and 

its estimated burden and cost. 


PWALKER on PROD1PC71 with NOTICES