3022 Federal Register / Vol. 74, No. 11 / Friday, January 16, 2009 / Notices 

1FERC confirmed and approved Rate Order No. 

WAPA–135 on April 14, 2008, in Docket No. EF08– 

5031–000. See United States Department of Energy, 

Western Area Power Administration, Pick-Sloan 

Missouri Basin Program, 123 FERC ¶ 62048 (April 

14, 2008). 

Base Capacity Base Revenue Requirement

Firm Billing Cap = 50%×

acity

Base Energy Base Revenue Requireme

=

= ×

$. /

%

3 21

50

kW month

nt

Annual Energy = 12 23 . mills/kWh

Drought Adder: A formula-based 

revenue requirement that includes 

future purchase power expense 

excluding timing power purchases, 

previous purchase power drought 

deficits, and interest on the purchase 

power drought deficits. For the period 

beginning on or after the first day of the 

first full billing period beginning on or 

after February 1, 2009, the Drought 

Adder revenue requirement is $26 

million. 

Drought Adder Capacity Drought Adder Revenue Requireme = 50%× nt

Firm Billing Capacity

Drought Adder Energy

= $. / 1 67 kW month

= × = 50 6 39 % $ . Drought Adder Revenue Requirement

Annual Energy

mills/kWh

Process: Any proposed change to the 

Base component will require a public 

process. The Drought Adder may be 

adjusted annually using the above 

formula for any costs attributed to 

drought of less than or equal to the 

equivalent of 2 mills/kWh to the LAP 

composite rate. Any planned 

incremental adjustment to the Drought 

Adder component greater than the 

equivalent of 2 mills/kWh to the LAP 

composite rate will require a public 

process. 

Adjustments: 

For Drought Adder: Adjustments 

pursuant to the Drought Adder 

component will be documented in a 

revision to this rate schedule. 

For Transformer Losses: If delivery is 

made at transmission voltage but 

metered on the low-voltage side of the 

substation, the meter readings will be 

increased to compensate for transformer 

losses as provided for in the contract. 

For Power Factor: None. The customer 

will be required to maintain a power 

factor at all points of measurement 

between 95-percent lagging and 95- 

percent leading. 

[FR Doc. E9–897 Filed 1–15–09; 8:45 am] 

BILLING CODE 6450–01–P 

DEPARTMENT OF ENERGY 

Western Area Power Administration 

Pick-Sloan Missouri Basin Program— 

Eastern Division-Rate Order No. 

WAPA–140 

AGENCY: Western Area Power 

Administration, DOE. 

ACTION: Notice of Order Concerning 

Firm Power Rates. 

SUMMARY: The Acting Deputy Secretary 

of Energy confirmed and approved Rate 

Order No. WAPA–140 and Rate 

Schedules P–SED–F10 and P–SED– 

FP10, placing firm power and firm 

peaking power rates from the Pick-Sloan 

Missouri Basin Program—Eastern 

Division (P–SMBP—ED) of the Western 

Area Power Administration (Western) 

into effect on an interim basis. The 

provisional rates will be in effect until 

the Federal Energy Regulatory 

Commission (FERC) 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 power investment and 

irrigation aid within the allowable 

periods. 

DATES: Rate Schedules P–SED–F10 and 

P–SED–FP10 will be placed into effect 

on an interim basis on the first day of 

the first full billing period beginning on 

or after February 1, 2009, and will 

remain in effect until FERC confirms, 

approves, and places the rate schedules 

in effect on a final basis ending 

December 31, 2013, or until the rate 

schedules are superseded. 

FOR FURTHER INFORMATION CONTACT: Mr. 

Robert J. Harris, Regional Manager, 

Upper Great Plains Region, Western 

Area Power Administration, 2900 4th 

Avenue North, Billings, MT 59101– 

1266, telephone (406) 247–7405, e-mail 

rharris@wapa.gov, or Ms. Linda CadyHoffman, Rates Manager, Upper Great 

Plains Region, Western Area Power 

Administration, 2900 4th Avenue North, 

Billings, MT 59101–1266, (406) 247– 

7439, e-mail cady@wapa.gov. 

SUPPLEMENTARY INFORMATION: The 

Deputy Secretary of Energy approved 

existing Rate Schedules P–SED–F9 and 

P–SED–FP9 for P–SMBP—ED firm and 

firm peaking electric service, 

respectively, on an interim basis on 

November 1, 2007 (72 FR 68,64,067 

November 14, 2007), for a 5-year period 

beginning on January 1, 2008, and 

ending December 31, 2012.1

Under Rate Schedule P–SED–F9, the 

composite rate is 24.49 mills per 

kilowatthour (mills/kWh), the firm 

energy rate is 13.99 mills/kWh, and the 

firm capacity rate is $5.65 per 

kilowattmonth (kWmonth). Under Rate 

Schedule P–SED–FP9, the firm peaking 

capacity rate is $5.10/kWmonth. These 

Rate Schedules are formula based with 

Base and Drought Adder components 

and provide for an up to 2 mills/kWh 

increase in the Drought Adder rate 

component. 

The current rate adjustment reflects a 

rate increase based on the P–SMBP 

Final Fiscal Year 2007 Power 

Repayment Study (PRS). The PRS sets 

the total annual P–SMBP—ED revenue 

requirement for 2009 for firm and firm 

peaking electric service at $283.0 

million, or a 19.9 percent increase. The 

current rates, including the 2 mills/kWh 

increase provided for under the Drought 

Adder formula rate component, are not 

sufficient to meet the P–SMBP—ED 

revenue requirements. 

The P–SMBP—ED revenue 

requirement increase is mainly 

attributed to the economic impacts of 

the drought. A decrease in hydro-power 

generation has caused purchase power 

expense to increase and revenue from 


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Federal Register / Vol. 74, No. 11 / Friday, January 16, 2009 / Notices 3023 

non-firm energy sales to decrease. There 

has been an increase in both the price 

and volume of purchase power needed 

to meet contractual commitments to 

Western’s customers. The purchase 

price of power is set by supply and 

demand on the open market. 

The existing firm electric service Rate 

Schedules P–SED–F9 and P–SED–FP9 

are being superseded by Rate Schedules 

P–SED–F10 and P–SED–FP10, 

respectively. Under Rate Schedule P– 

SED–F10, the provisional rates for firm 

electric services will result in a 

combined composite rate of 29.34 mills/ 

kWh. The energy rate will be 16.71 

mills/kWh (a Base component of 9.27 

mills/kWh and a Drought Adder 

component of 7.44 mills/kWh), and the 

capacity rate will be $6.80/kWmonth (a 

Base component of $3.80/kWmonth and 

a Drought Adder component of $3.00/ 

kWmonth). Under Rate Schedule P– 

SED–FP10, the provisional rates for firm 

peaking electric services consist of a 

capacity charge of $6.20/kWmonth (a 

Base component of $3.40/kWmonth and 

a Drought Adder component of $2.80/ 

kWmonth) and an energy charge of 

16.71 mills/kWh. 

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 the Administrator 

of Western; (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 FERC. 

Existing Department of Energy 

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 00–001.00C, 10 CFR part 

903, and 18 CFR part 300, I hereby 

confirm, approve, and place Rate Order 

No. WAPA–140, the proposed P– 

SMBP—ED firm power, and firm 

peaking power rates into effect on an 

interim basis. 

The new Rate Schedules P–SED–F10 

and P–SED–FP10 will be promptly 

submitted to FERC for confirmation and 

approval on a final basis. 

Dated: January 8, 2009. 

Jeffrey F. Kupfer, 

Acting Deputy Secretary. 

Department of Energy 

Deputy Secretary 

In the matter of: 

Western Area Power Administration Rate 

Adjustment for the Pick-Sloan Missouri 

Basin Program—Eastern Division; Rate Order 

No. WAPA–140; 

Order Confirming, Approving, and Placing 

the Pick-Sloan Missouri Basin Program— 

Eastern Division Firm Power and Firm 

Peaking Power Service Rates Into Effect on an 

Interim Basis 

The firm and firm peaking electric 

service rates for the Pick-Sloan Missouri 

Basin Program—Eastern Division were 

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 

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)) and 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 the Administrator 

of Western; (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 

Federal Energy Regulatory 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: 

Administrator: The Administrator of 

the Western Area Power 

Administration. 

Base: Revenue requirement 

component of the power rate including 

annual operation and maintenance 

expenses, investment repayment and 

associated interest, normal timing 

power purchases, and transmission 

costs. 

Capacity: The electric capability of a 

generator, transformer, transmission 

circuit, or other equipment. It is 

expressed in kilowatts. 

Capacity Charge: The rate which sets 

forth the charges for capacity. It is 

expressed in dollars per kilowattmonth. 

Composite Rate: The rate for 

commercial firm power which is the 

total annual revenue requirement for 

capacity and energy divided by the total 

annual energy sales. It is expressed in 

mills per kilowatthour and used for 

comparison purposes. 

Corps: The United States Army Corps 

of Engineers. 

CROD: Contract Rate of Delivery. The 

maximum amount of capacity and 

energy allocated to a preference 

customer for a period specified under a 

contract. 

Customer: An entity with a contract 

that is receiving service from Western’s 

Upper Great Plains Region. 

Deficits: Deferred or unrecovered 

annual and/or interest expenses. 

DOE: United States Department of 

Energy. 

DOE Order RA 6120.2: An order 

outlining power marketing 

administration financial reporting and 

rate-making procedures. 

Drought Adder: Formula-based 

revenue requirement component 

including costs associated with the 

drought. 

Energy: Measured in terms of the 

work it is capable of doing over a period 

of time. It is expressed in kilowatthours. 

Energy Charge: 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: Federal Energy Regulatory 

Commission. 

Firm: A type of product and/or service 

available at the time requested by the 

customer. 

FRN: Federal Register notice. 

Fry-Ark: Fryingpan-Arkansas Project. 

FY: Fiscal Year; October 1 to 

September 30. 

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. 

LAP: Loveland Area Projects. 

Load Factor: The ratio of average load 

in kW supplied during a designated 

period to the peak or maximum load in 

kW occurring in that period. 

mills/kWh: Mills per kilowatthour— 

the unit of charge for energy (equal to 

one tenth of a cent or one thousandth 

of a dollar). 

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3024 Federal Register / Vol. 74, No. 11 / Friday, January 16, 2009 / Notices 

MISO: Midwest Independent 

Transmission System Operator. 

MW: Megawatt—the electrical unit of 

capacity that equals 1 million watts or 

1,000 kilowatts. 

NEPA: National Environmental Policy 

Act of 1969 (42 U.S.C. 4321, et seq.). 

Non-timing Power Purchases: Power 

purchases that are not related to 

operational constraints such as 

management of endangered species, 

species habitat, water quality, 

navigation, control area purposes, etc. 

O&M: Operation and Maintenance. 

P–SMBP: The Pick-Sloan Missouri 

Basin Program. 

P–SMBP—ED: Pick-Sloan Missouri 

Basin Program—Eastern Division. 

P–SMBP—WD: Pick-Sloan Missouri 

Basin Program—Western Division. 

Power: Capacity and energy. 

Power Factor: The ratio of real to 

apparent power at any given point and 

time in an electrical circuit. Generally, 

it is expressed as a percentage. 

Preference: The provisions of 

Reclamation Law which require 

Western to first make Federal power 

available to certain entities. For 

example, section 9(c) of the Reclamation 

Project Act of 1939 (43 U.S.C. 485h(c)) 

states that preference in the sale of 

Federal power shall be given to 

municipalities and other public 

corporations or agencies and also to 

cooperatives and other nonprofit 

organizations financed in whole or in 

part by loans made under the Rural 

Electrification Act of 1936. 

Provisional Rate: A rate which has 

been confirmed, approved, and placed 

into effect on an interim basis by the 

Deputy Secretary. 

PRS: Power Repayment Study. 

Rate Brochure: An August 2008 

document explaining the rationale and 

background for the rate proposal 

contained in this Rate Order. 

Reclamation: The United States 

Department of the Interior, Bureau of 

Reclamation. 

Reclamation Law: A series of Federal 

laws. Viewed as a whole, these laws 

create the originating framework under 

which Western markets power. 

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. 

RMR: The Rocky Mountain Customer 

Service Region of the Western Area 

Power Administration. 

SPP: Southwest Power Pool. 

Timing Power Purchases: Power 

purchases that are due to operational 

constraints (e.g. management of 

endangered species, species habitat, 

water quality, navigation, control area 

purposes, etc.) and not associated with 

the drought. 

UGPR: The Upper Great Plains 

Customer Service Region of the Western 

Area Power Administration. 

Western: The United States 

Department of Energy, Western Area 

Power Administration. 

Effective Date 

The new provisional rates will take 

effect on the first day of the first full 

billing period beginning on or after 

February 1, 2009, and will remain in 

effect until December 31, 2013, pending 

approval by FERC 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, in 

developing these rates. The steps 

Western took to involve interested 

parties in the rate process were: 

1. The proposed rate adjustment 

process began April 9, 2008, when 

Western’s UGPR mailed a notice 

announcing informal customer meetings 

to all P–SMBP—ED preference 

customers and interested parties. The 

informal meetings were held on April 

29, 2008, in Denver, Colorado, and on 

April 30, 2008, in Sioux Falls, South 

Dakota. At these informal meetings, 

Western explained the rationale for the 

rate adjustment, presented rate designs 

and methodologies, and answered 

questions. 

2. A Federal Register notice, 

published on August 15, 2008 (73 FR 

47945) announced the proposed rates 

for P–SMBP—ED, began a public 

consultation and comment period and 

announced the public information and 

public comment forums. 

3. On August 18, 2008, Western 

mailed letters to all P–SMBP—ED 

preference customers and interested 

parties transmitting the FRN published 

on August 15, 2008. 

4. On August 29, 2008, a letter was 

mailed to preference customers and 

interested parties informing them of a 

$400,000 misstatement in the FRN 

published revenue requirement. 

5. On September 9, 2008, at 9 a.m. 

(MDT), Western held a public 

information forum at the Ramada Plaza 

Hotel in Northglenn, Colorado. Western 

provided updates to the proposed firm 

power rates for the P–SMBP, which 

encompasses the P–SMBP—ED and LAP 

rates. Western also answered questions 

and gave notice that more information 

was available in the rate brochure. 

6. On September 9, 2008, at 11:30 a.m. 

(MDT), following the public information 

forum, and at the same location, a 

public comment forum was held. The 

comment forum gave the public an 

opportunity to comment for the record. 

No oral or written comments were 

received at this forum. 

7. On September 10, 2008, at 8 a.m. 

(CDT), Western held a public 

information forum at the Holiday Inn in 

Sioux Falls, South Dakota. Western 

provided updates to the proposed firm 

power rates for the P–SMBP, which 

encompasses the P–SMBP—ED and LAP 

rates. Western also answered questions 

and gave notice that more information 

was available in the rate brochure. 

8. On September 10, 2008, at 10:30 

a.m. (CDT), following the public 

information forum, and at the same 

location, a public comment forum was 

held. The comment forum gave the 

public an opportunity to comment for 

the record. One oral comment was 

received at this forum. 

9. Western provided a Web site which 

contains all of the letters, time frames, 

dates, and locations of forums, 

documents discussed at the information 

meetings, FRNs, rate brochure, and all 

other information about this rate process 

for easy customer access. The Web site 

is located at http://www.wapa.gov/ugp/ 

rates/2009FirmRateAdjust. 

10. During the consultation and 

comment period, which ended 

November 13, 2008, Western received 

17 comment letters. One comment letter 

was rescinded. Western also received an 

oral comment. All formally submitted 

comments have been considered in 

preparing this Rate Order. 

Comments 

Written comments were received from 

the following organizations: 

City of Blue Hill, Nebraska. 

City of Burwell, Nebraska (2). 

City of Fort Morgan, Colorado. 

City of Sargent, Nebraska. 

City of Wall Lake, Iowa. 

City of West Point, Nebraska. 

City of Wisner, Nebraska. 

City of Wood River, Nebraska. 

Corn Belt Power Cooperative, Iowa. 

Mid-West Electric Consumers 

Association, Colorado. 

North Iowa Municipal Electric 

Cooperative Association, Iowa. 

Spencer Municipal Utilities, Iowa. 

Village of Oxford, Nebraska. 

Village of Shickley, Nebraska. 

Village of Spencer, Nebraska. 

Village of Stuart, Nebraska. 

A representative of the following 

organization made an oral comment: 

Minnesota Municipal Utilities, 

Minnesota. 

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Federal Register / Vol. 74, No. 11 / Friday, January 16, 2009 / Notices 3025 

Project Description 

The P–SMBP was authorized by 

Congress in section 9 of the Flood 

Control Act of December 22, 1944, 

commonly referred to as the 1944 Flood 

Control Act. This multipurpose program 

provides flood control, irrigation, 

navigation, recreation, preservation and 

enhancement of fish and wildlife, and 

power generation. Multipurpose 

projects have been developed on the 

Missouri River and its tributaries in 

Colorado, Montana, Nebraska, North 

Dakota, South Dakota, and Wyoming. 

In addition to the multipurpose water 

projects authorized by Section 9 of the 

Flood Control Act of 1944, certain other 

existing projects have been integrated 

with the P–SMBP for power marketing, 

operation, and repayment purposes. The 

Colorado-Big Thompson, Kendrick, and 

Shoshone Projects were combined with 

the P–SMBP in 1954, followed by the 

North Platte Project in 1959. These 

projects are referred to as the 

‘‘Integrated Projects’’ of the P–SMBP. 

The Flood Control Act of 1944 also 

authorized the inclusion of the Fort 

Peck Project with the P–SMBP for 

operation and repayment purposes. The 

Riverton Project was integrated with the 

P–SMBP in 1954 and in 1970 was 

reauthorized as a unit of P–SMBP. 

The P–SMBP is administered by two 

regions. The UGPR, with a regional 

office in Billings, Montana, markets 

power from the Eastern Division of P– 

SMBP, and the RMR, with a regional 

office in Loveland, Colorado, markets 

the Western Division power of P–SMBP. 

The UGPR markets power in western 

Iowa, western Minnesota, Montana east 

of the Continental Divide, North Dakota, 

South Dakota, and the eastern twothirds of Nebraska. The RMR markets P– 

SMBP—WD power, which in 

combination with Fry-Ark power is 

known as LAP power, in northeastern 

Colorado, east of the Continental Divide 

in Wyoming, west of the 101st meridian 

in Nebraska, and most of Kansas. The P– 

SMBP power is marketed to 

approximately 300 firm power 

customers by the UGPR and 

approximately 60 firm power customers 

by the RMR. 

Power Repayment Study—Firm Power 

Rate 

Western prepares a PRS each FY to 

determine if revenues will be sufficient 

to repay, within the required time, all 

costs assigned to the P–SMBP. 

Repayment criteria are based on law, 

policies including DOE Order RA 

6120.2, and authorizing legislation. To 

meet Cost Recovery Criteria outlined in 

DOE Order RA 6120.2, a revised study 

and rate adjustment has been developed 

to demonstrate that sufficient revenues 

will be collected under proposed rates 

to meet future obligations. 

Existing and Provisional Rates 

Eastern Division 

Under Rate Schedule P–SED–F9, the 

composite rate is 24.49 mills/kWh, the 

firm energy rate is 13.99 mills/kWh, and 

the firm capacity rate is $5.65/ 

kWmonth. For Rate Schedule P–SED– 

FP9 the firm peaking capacity rate is 

$5.10/kWmonth. These Rate Schedules 

are formula based with Base and 

Drought Adder components and provide 

for an up to a 2 mills/kWh increase in 

the Drought Adder rate component. 

The current rate adjustment reflects a 

rate increase based on the P–SMBP 

Fiscal Year 2007 PRS. The PRS sets the 

total annual P–SMBP—ED revenue 

requirement for 2009 for firm and firm 

peaking electric service at $283.0 

million, or a 19.9 percent increase. 

A comparison of the existing and 

provisional firm power and firm 

peaking power rates follow: 

TABLE 1—COMPARISON OF EXISTING AND PROVISIONAL RATES PICK-SLOAN MISSOURI BASIN PROGRAM—EASTERN

DIVISION

Firm electric service Current rates Provisional rates Percent change 

Rate Schedules P–SED–F9/P–SED– 

FP9 

P–SED–F10/P–SED– 

FP10 

Firm and Firm Peaking Revenue Requirement (million) ..................... $235 .9 $283 .0 19.9 

Composite Rate (mills/kWh) ................................................................ 24 .49 29 .34 19.8 

Firm Capacity Rate (/kWmonth) .......................................................... $5 .65 $6 .80 20.4 

Firm Energy Rate (mills/kWh) ............................................................. 13 .99 16 .71 19.4 

Firm Peaking Capacity Rate (/kWmonth) ............................................ $5 .10 $6 .20 21.6 

Firm Peaking Energy Rate (mills/kWh)1 .............................................. 13 .99 16 .71 19.4 

1Firm Peaking Energy is normally returned. This rate will be assessed in the event Firm Peaking Energy is not returned. 

Western Division 

The LAP rate is designed to recover 

the P–SMBP—WD revenue requirement 

for the P–SMBP and the revenue 

requirement for Fry-Ark. The 

adjustment to the LAP rate is a separate 

formal rate process which is 

documented in Rate Order No. WAPA– 

142. Rate Order No. WAPA–142 is 

scheduled to go into effect on the first 

day of the first full billing period after 

the Acting Deputy Secretary of Energy 

approves the rate. 

Certification of Rates 

Western’s Administrator certified that 

the Provisional Rates for P–SMBP—ED 

firm power and firm peaking power 

rates are the lowest possible rates 

consistent with sound business 

principles. The Provisional Rates were 

developed following administrative 

policies and applicable laws. 

P–SMBP—ED Firm Power Rate 

Discussion 

According to Reclamation Law, 

Western must establish power rates 

sufficient to recover operation, 

maintenance, purchased power and 

interest expenses, and repay power 

investment and irrigation aid. 

The P–SMBP—ED firm power and 

firm peaking power rates must be 

increased due to the economic impact of 

the drought, increased annual expenses, 

increased investments, and increased 

interest expense associated with 

deficits. 

Under Rate Schedule P–SED–F10, 

Western will continue identifying its 

firm electric service revenue 

requirement using Base and Drought 

Adder rate components. The Base rate 

component is a revenue requirement 

that includes annual operation and 

maintenance expenses, investment 

repayment and associated interest, 

normal timing power purchases, and 

transmission costs. Western’s normal 

timing power purchases are purchases 

due to operational constraints (e.g., 

management of endangered species 

habitat, water quality, navigation, etc.) 

and are not associated with the current 

drought. The Base component cannot be 

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3026 Federal Register / Vol. 74, No. 11 / Friday, January 16, 2009 / Notices 

adjusted by Western without a public 

process. 

The Drought Adder rate component is 

a formula-based revenue requirement 

that includes costs attributable to the 

past and present drought conditions 

within the Pick-Sloan Program. The 

Drought Adder rate component includes 

costs associated with future non-timing 

power purchases to meet firm power 

contractual obligations not covered with 

available system generation due to the 

drought, previously incurred deficits 

due to purchased power debt that 

resulted from non-timing power 

purchases made during this drought, 

and the interest associated with the 

previously incurred and future drought 

deficit. The Drought Adder rate 

component is designed to repay 

Western’s drought deficit within 10 

years from the time the debt was 

incurred, using balloon-payment 

methodology. For example, the drought 

deficit incurred by Western in 2007 will 

be repaid by 2017. 

The annual revenue requirement 

calculation will continue to be 

summarized by the following formula: 

Annual Revenue Requirement = Base 

Revenue Requirement + Drought Adder 

Revenue Requirement. Under this 

Provisional Rate, effective February 1, 

2009, the P–SMBP—ED annual revenue 

requirement equals $294.1 million and 

is comprised of a Base revenue 

requirement of $163.5 million plus a 

Drought Adder revenue requirement of 

$130.6 million. Both the Base and 

Drought Adder rate components recover 

portions of the firm power revenue 

requirement, firm peaking power, and 

associated 5 percent discount revenue 

necessary to equal the P–SMBP—ED 

revenue requirement. A comparison of 

the current and proposed rate 

components are listed in Table 2. 

TABLE 2—SUMMARY OF P–SMBP—ED RATE COMPONENTS

Existing rates P–SED–F9/P–SED–FP9 Provisional rates P–SED–F10/ 

P–SED–FP10 

Base 

component 

Drought 

adder 

component 

Total Base 

component 

Drought 

adder 

component 

Total 

Firm Capacity Rate (/kWmonth) ...................................... $3.65 $2.00 $5.65 $3.80 $3.00 $6.80 

Firm Energy Rate (mills/kWh) .......................................... 8.93 5.06 13.99 9.27 7.44 16.71 

Firm Peaking Capacity Rate (/kWmonth) ........................ $3.25 $1.85 $5.10 $3.40 $2.80 $6.20 

Firm Peaking Energy Rate (mills/kWh)1 .......................... 8.93 5.06 13.99 9.27 7.44 16.71 

1Firm peaking energy is normally returned. This will be assessed in the event firm peaking energy is not returned. 

As set forth in Table 2 above, 

provisional Rate Schedule P–SED–F10 

has a firm capacity rate of $6.80/ 

kWmonth and a firm energy rate of 

16.71 mills/kWh. Under proposed Rate 

Schedule P–SED–FP10, the firm peaking 

capacity rate will increase to $6.20/ 

kWmonth, or a 21.6 percent increase. 

Peaking energy is either returned to 

Western or paid for in accordance with 

the terms of the contract between 

Western and the peaking power 

customer. 

Continuing to identify the firm 

electric service revenue requirement 

using Base and Drought Adder rate 

components will assist Western in 

presenting the effects of the drought 

within the P–SMBP, demonstrating 

repayment of the drought related costs, 

and allowing Western to be more 

responsive to changes in drought related 

expenses. Western will continue to 

charge and bill customers firm electric 

service rates for energy and capacity, 

which are the sum of the Base and 

Drought Adder rate components. 

Western reviews its firm electric 

service rates annually. Western will 

review the Base rate component after 

the annual PRS is completed, generally 

in the first quarter of the calendar year. 

If an adjustment to the Base rate 

component is necessary, Western will 

initiate a public process pursuant to 10 

CFR part 903 prior to making an 

adjustment. 

In accordance with the original 

implementation of the Drought Adder 

rate component, Western will continue 

to review the Drought Adder rate 

component each September to 

determine if drought costs differ from 

those projected in the PRS. If drought 

costs differ, Western will determine if 

an adjustment to the Drought Adder rate 

component is necessary. Western will 

notify customers by letter each October 

of the planned incremental or 

decremental adjustment and implement 

the adjustment in the January billing 

cycle. Although decremental 

adjustments to the Drought Adder rate 

component will occur as drought costs 

are repaid, the adjustments cannot 

result in a negative Drought Adder rate 

component. To give customers advance 

notice, Western will conduct a 

preliminary review of the Drought 

Adder rate component in early summer 

and notify customers by letter of the 

estimated change to the Drought Adder 

rate component for the following 

January. Western will verify the final 

Drought Adder rate component 

adjustment by notification in the 

October letter to the customers. 

Implementing the Drought Adder rate 

component adjustment on January 1 of 

each year will help keep the drought 

deficits from escalating as quickly, will 

lower the interest expense due to 

drought deficits, will demonstrate 

responsible deficit management, and 

will provide prompt drought deficit 

repayments. 

Western’s current and Provisional 

Rate schedules provide for a formulabased adjustment of the Drought Adder 

rate component of up to 2 mills/kWh. 

The 2 mills/kWh cap is intended to 

place a limit on the amount the Drought 

Adder formula can be adjusted relative 

to associated drought costs without 

initiating a public process to recover 

costs attributable to the Drought Adder 

formula rate for any one-year cycle. 

Statement of Revenue and Related 

Expenses 

The following Table 3 provides a 

summary of projected revenue and 

expense data for the total P–SMBP, 

including both the Eastern and Western 

Divisions, firm electric service revenue 

requirement through the 5-year rate 

approval period. 

The firm power rates for both 

divisions have been developed with the 

following revenues and expenses for the 

P–SMBP: 

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Federal Register / Vol. 74, No. 11 / Friday, January 16, 2009 / Notices 3027 

2Western’s Continuing Fund (Emergency Fund) 

Policy can be found at http://www.wapa.gov/ 

powerm/pdf/repaypolicy.pdf. 

TABLE 3—TOTAL P–SMBP FIRM POWER COMPARISON OF 5-YEAR RATE PERIOD (FY 2009–2013) TOTAL REVENUES AND

EXPENSES

Current rate 

($000) 

Provisional 

rate 

($000) 

Difference 

($000) 

Total Revenues ............................................................................................................................ 2,124,002 2,417,497 293,495 

Revenue Distribution 

Expenses: 

O&M ...................................................................................................................................... 904,589 859,559 (45,030) 

Purchased Power ................................................................................................................. 155,654 431,180 275,526 

Interest .................................................................................................................................. 528,272 639,356 111,084 

Transmission ........................................................................................................................ 55,596 65,963 10,367 

Total Expenses .............................................................................................................. 1,644,111 1,996,058 351,947 

Principal Payments: 

Capitalized Expenses (Deficits)1 .......................................................................................... 150,549 351,517 200,968 

Original Project and Additions1 ............................................................................................ 263,052 1,546 (261,506) 

Replacements1 ..................................................................................................................... 3,314 2,704 (610) 

Irrigation Aid ......................................................................................................................... 62,976 65,672 2,696 

Total Principal Payments .............................................................................................. 479,891 421,439 (58,452) 

Total Revenue Distribution ..................................................................................... 2,124,002 2,417,497 293,495 

1 Due to the deficit or near deficit conditions between 1999 and 2008, revenues generated in the cost evaluation period are applied toward repayment of deficits rather than repayment of project additions and replacements. All deficits are projected to be repaid by 2017. 

Basis for Rate Development 

The existing rates for P–SMBP—ED 

firm power in Rate Schedule P–SED–F9, 

which expire December 31, 2012, no 

longer provide sufficient revenues to 

pay all annual costs, including interest 

expense, and repay investment and 

irrigation aid within the allowable 

period. The adjusted rates reflect 

increases due to the economic impact of 

the drought, increased annual expenses, 

increased investments, and increased 

interest expense associated with 

investments and drought deficits. The 

Provisional Rates will provide sufficient 

revenue to pay all annual costs, 

including interest expense, and repay 

power investment and irrigation aid 

within the allowable periods. The 

Provisional Rates will take effect on 

February 1, 2009, and will remain in 

effect on an interim basis, pending 

FERC’s confirmation and approval of 

them or substitute rates on a final basis, 

through December 31, 2013. 

Emergency Fund Discussion 

Due to continuing below-normal 

hydropower generation, Western may 

need to use the Continuing Fund 

(Emergency Fund) to pay for 

unanticipated purchase power and 

wheeling expenses necessary to meet its 

contractual obligations for the sale and 

delivery of power to its customers. 

Should Western use this funding 

mechanism, Western will replenish the 

Continuing Fund (Emergency Fund) in 

accordance with law and Western’s 

current repayment policy.2

Comments 

The comments and responses below 

regarding the firm and firm peaking 

electric service rates are paraphrased for 

brevity when not affecting the meaning 

of the statement(s). Direct quotes from 

comment letters are used for 

clarification when necessary. 

The issues discussed are (1) Firm 

Power Rate and (2) MISO Markets. 

1. Firm Power Rate 

Comment: Western received 

numerous comments from customers 

stating that they understand the need for 

the rate increases and support the 

concept of the Drought Adder, which 

provides a set window during which 

drought-related expenses are repaid. 

Response: Western appreciates the 

customer support received for the rate 

adjustment proposal. Western continues 

separation of the annual revenue 

requirement into Base and Drought 

Adder components. 

Comment: Many comments were 

received from customers that showed 

appreciation for Western’s commitment 

to keep power customers informed and 

involved throughout this rate process. 

Customers were grateful for past costcutting measures and encouraged 

Western’s continued vigilance in 

keeping controllable costs as low as 

possible. 

Response: Western is pleased with the 

level of customer interest and 

participation in the public meetings. 

Under the Flood Control Act of 1944, 

power is to be sold at the lowest 

possible rates consistent with sound 

business principles. Western is 

committed to keeping controllable costs 

as low as possible while continuing to 

deliver reliable cost-based hydroelectric 

power and related services. 

Comment: Customers state that they 

are looking forward to working with 

Western’s staff on the projected Base 

rate adjustments as they pertain to 

Western’s draft Strategic Plan and 

Western’s potential involvement in 

changes associated with MISO and SPP. 

Response: Western’s goal is to work 

closely with our customers throughout 

this rate, as well as any future rate 

adjustments. Changes to the Base Rate 

are made through a public process and 

allow for input. 

Comment: Two customers were 

opposed to the firm peaking rate and 

questioned whether it reflects the costs 

associated with the drought and 

delivery of peaking power. It was noted 

that the firm peaking rate is being 

increased at approximately the same 

percentage rate as the firm power rate, 

which the commenting customers felt 

may not be fair and equitable. These 

customers wanted additional 

information regarding the firm peaking 

contracts so the impact on the rates can 

be better understood and evaluated. It 

was understood that Western allows 

peaking energy to be returned. They 

questioned under what terms and 

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3028 Federal Register / Vol. 74, No. 11 / Friday, January 16, 2009 / Notices 

conditions peaking customers are 

allowed to return energy and whether 

peaking energy is allowed to be returned 

off-peak. Customers asked if Western 

makes market purchases to fulfill 

Western’s peaking contracts. The 

customers asked for assurance from 

Western that the firm peaking rate is 

fairly priced based on the nature of the 

product and its historical and future 

contributions to the bottom line. 

Response: Western separated the firm 

and firm peaking rates and developed 

rate designs for both firm power and 

firm peaking power in the FRN 

published November 14, 2007 (72 FR 

¶ 64067). In development of this firm 

peaking rate design, Western analyzed 

historical peaking data and concluded 

that this rate reflects the firm peaking 

customer’s historical usage and their 

impact on the drought costs. During the 

current rate adjustment process, 

Western concluded that there has not 

been substantial change to the firm 

peaking usage or power markets since 

the introduction of the new firm 

peaking rate design that would support 

revisiting the rate design at this time. 

Western believes that both the firm and 

firm peaking customers are being treated 

equitably with the current rate designs. 

The firm peaking rate design accurately 

reflects the value and restrictions of the 

peaking product. 

Comment: One customer would like 

to evaluate the voltage discount and was 

concerned that it may be too high in 

light of the recent drought-related 

increases. The concern was that billing 

amounts have grown since the voltage 

discount was put into place and now 

the discount may be too much in 

comparison to the actual cost. 

Response: Historically, Western has 

provided a 5-percent voltage discount as 

a provision to the firm power rate 

schedule. The purpose of the discount 

is to provide the discount on firm power 

sales to customers who receive 

deliveries at higher transmission voltage 

and relieve Western of substation 

delivery costs. Reclamation began, and 

Western continues, the 5-percent 

voltage discount to customers meeting 

the criteria. Up to this time, Western has 

not been formally asked to change the 

discount percentage and has not 

evaluated the impacts of such a change 

on the firm power customers. Western is 

open to discussion among our 

customers and exploring options 

regarding the 5-percent voltage 

discount; but until additional customers 

request a review or modification of this 

provision, Western will continue 

applying the discount. 

Comment: One customer recognized 

the impacts that the extended drought 

has had on the current financial status 

of the P–SMBP and expressed support 

for the proposed firm power rate 

increases. The customer also stated that 

the repayment of Federal investment 

through Federal power rates is taken 

very seriously. In the future, the 

Drought Adder will help to avoid a 

repetition of the financial impacts that 

are seen today. 

Response: Western acknowledges the 

extended drought, its financial impacts, 

and the need for a firm power rate 

increase as well. The Drought Adder 

will allow Western to be more 

responsive to the changing hydrological 

conditions. 

Comment: A customer representative 

acknowledged the financial challenges 

of this drought and made note of the 

difficulties Federal power customers are 

confronted with in fulfilling their 

financial responsibilities to the Federal 

government. They noted the good water 

years in the 1990s generated significant 

revenue surplus to P–SMBP financial 

requirements. Also noted was Western’s 

administration of repayment according 

to repayment policies and the 

repayment of a significant amount of 

capital investment ahead of schedule. 

This early repayment benefitted both P– 

SMBP customers and the Federal 

government but left no financial 

resources to deal with drought. Thus, 

the current repayment practices and 

policies exacerbate the impacts of the 

natural swings in hydrology. When the 

drought deficit is repaid, there will still 

be a substantial amount of paid-ahead 

investments for the P–SMBP. The 

customer would like to work with 

Western to address this issue. 

Response: Western acknowledges the 

financial impacts of the current drought 

and believes the ratemaking policy of 

identifying the Base and Drought Adder 

components will make the rates more 

responsive to hydrological changes 

caused by both drought and flush water 

years. The Drought Adder component 

may be adjusted annually up to 2 mills/ 

kWh without a public process to quickly 

address drought impacts, and the Base 

Rate component can only be adjusted 

through a public process. This practice 

will lower interest expense due to 

drought deficits and demonstrate 

responsible deficit management. 

Western acknowledges the customer 

group statements regarding Western’s 

adherence to repayment policies and the 

associated repayment of a significant 

amount of capital investment ahead of 

schedule in the 1990s. Prepayment is an 

integral part of the long-term plan for P– 

SMBP and has provided rate stability for 

consumers while meeting Federal 

repayment obligations. The ability to 

reduce the Drought Adder rate 

component when normal hydrological 

conditions return to P–SMBP will allow 

appropriate recognition of repayment 

obligations. Western appreciates the 

customers’ support and willingness to 

work with Western and will continue to 

discuss issues, impacts, and possible 

solutions with the customers. 

2. MISO Markets 

Comment: Western has received 

numerous comments concerning the 

issue of whether to join MISO and its 

Day Two Markets. The comments 

support a thorough review of costs and 

benefits to all of Western’s customers 

before a change is made. Comments 

suggest that administrative costs 

associated with the Day Two Markets 

may impose a significant burden, 

especially on smaller customers. There 

were concerns that if Western joins 

MISO and other area transmission 

owners that serve the customers join 

SPP there could be significant cost 

issues associated with the delivery of 

Western’s allocation to Preference 

customer loads. Comments stated that if 

there are benefits to participating in the 

Day Two Market those benefits should 

flow to all of Western’s customers, not 

just those that participate in joint 

dispatching arrangements inside the 

Integrated System. Concerns are that 

costs associated to deliver Western’s 

allocations to the edge of the system 

should be recovered as part of the total 

system transmission rate recovery, as it 

has been done in the past. 

Response: This comment is not 

directly related to the proposed rate 

action. However, Western is actively 

addressing these issues as well as other 

options and evaluating them based on 

costs and benefits to Western’s 

customers. 

Comment: A commenter noted that 

MISO intends to start an ancillary 

service market; and when that occurs, 

Western has preference power 

customers that are served in the MISO 

footprint. The question was asked does 

Western have avoided costs due to the 

MISO market providing those ancillary 

services; specifically, are there avoided 

costs in Schedule 3, Regulation and 

Frequency Response; Schedule 5, 

Operating Reserves Spinning; and 

Schedule 6, Operating Reserves 

Supplemental. 

Response: This comment is not 

directly related to the proposed rate 

action. Western is actively evaluating its 

obligations to customers in the MISO 

Ancillary Services Market footprint. As 

Western moves forward in evaluating 

the impacts on market participation and 

changes for customers, Western will 

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Federal Register / Vol. 74, No. 11 / Friday, January 16, 2009 / Notices 3029 

seek input from customers and will 

continue to keep customers informed of 

decisions regarding these matters. 

Availability of Information 

Information about this rate 

adjustment, including the PRS, 

comments, letters, memorandums, and 

other supporting materials that was 

used to develop the Provisional Rates is 

available for public review in the Upper 

Great Plains Regional Office, Western 

Area Power Administration, 2900 4th 

Avenue North, Billings, Montana. 

Ratemaking Procedure Requirements 

Environmental Compliance 

In compliance with the National 

Environmental Policy Act (NEPA) of 

1969, 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 

has determined that this action is 

categorically excluded from preparing of 

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. 

Submission to the Federal Energy 

Regulatory Commission 

The Provisional Rates herein 

confirmed, approved, and placed into 

effect, together with supporting 

documents, will be submitted to FERC 

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 

February 1, 2009, Rate Schedules P– 

SED–F10 and P–SED–FP10 for the PickSloan Missouri Basin Program—Eastern 

Division Project of the Western Area 

Power Administration. These rate 

schedules shall remain in effect on an 

interim basis, pending FERC’s 

confirmation and approval of them or 

substitute rates on a final basis through 

December 31, 2013. 

Dated: January 8, 2009. 

Jeffrey F. Kupfer, 

Acting Deputy Secretary. 

Rate Schedule P–SED–F10 

(Supersedes Schedule P–SED–F9) 

Effective February 1, 2009 

United States Department of Energy, 

Western Area Power Administration 

Pick-Sloan Missouri Basin Program— 

Eastern Division Montana, North 

Dakota, South Dakota, Minnesota, 

Iowa, Nebraska 

Schedule of Rates for Firm Power 

Service 

(Approved Under Rate Order No. 

WAPA–140) 

Effective: The first day of the first full 

billing period beginning on or after 

February 1, 2009, through December 31, 

2013. 

Available: Within the marketing area 

served by the Eastern Division of the 

Pick-Sloan Missouri Basin Program. 

Applicable: To the power and energy 

delivered to customers as firm power 

service. 

Character: Alternating current, 60 

hertz, three phase, delivered and 

metered at the voltages and points 

established by contract. 

Monthly Rates 

Demand Charge: $6.80 for each 

kilowatt per month (kWmonth) of 

billing demand. 

Energy Charge: 16.71 mills per 

kilowatthour (kWh) for all energy 

delivered as firm power service. 

Billing Demand: The billing demand 

will be as defined by the power sales 

contract. 

Charge Components 

Base: A fixed revenue requirement 

that includes operation and 

maintenance expense, investments and 

replacements, interest on investments 

and replacements, normal timing 

purchase power costs (purchases due to 

operational constraints, not associated 

with drought), and transmission costs. 

The Base revenue requirement is $163.5 

million. 

Base Demand Base Revenue Requirement

Firm Metered Billi = 50%×

ng Units

Base Energy Base Revenue Requir

=

= ×

$. /

%

3 80

50

kW month

ement

Annual Energy = $ . 9 27 mills/kWh

Drought Adder: A formula-based 

revenue requirement that includes 

future purchase power expense 

excluding timing purchases, previous 

purchase power drought deficits, and 

interest on the purchase power drought 

deficits. For the period beginning 

February 1, 2009, the Drought Adder 

revenue requirement is $130.6 million. 

Drought Adder Demand Drought Adder Revenue Requirement = 50%×

Firm Metered Billing Units

Drought Adder Ene

= $. / 3 00 kW month

rgy Drought Adder Revenue Requirement

Annual Energy = × = 50 7 % $ .44 mills/kWh

Process: Any proposed change to the 

Base component will require a public 

process. The Drought Adder component 

may be adjusted annually using the 

above formula for any costs attributed to 

drought of less than or equal to the 

equivalent of 2 mills/kWh to the Power 

Repayment Study (PRS) composite rate. 

Any planned incremental adjustment to 

the Drought Adder component greater 

than the equivalent of 2 mills/kWh to 

the PRS composite rate will require a 

public process. 

Adjustments 

For Drought Adder: Adjustments 

pursuant to the Drought Adder 


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3030 Federal Register / Vol. 74, No. 11 / Friday, January 16, 2009 / Notices 

1Firm peaking energy is normally returned. This 

rate will be assessed in the event firm peaking 

energy is not returned. 

component will be documented in a 

revision to this rate schedule. 

For Character and Conditions of 

Service: Customers who receive 

deliveries at transmission voltage may 

in some instances be eligible to receive 

a 5-percent discount on demand and 

energy charges when facilities are 

provided by the customer that results in 

a sufficient savings to Western to justify 

the discount. The determination of 

eligibility for receipt of the voltage 

discount shall be exclusively vested in 

Western. 

For Billing of Unauthorized Overruns: 

For each billing period in which there 

is a contract violation involving an 

unauthorized overrun of the contractual 

firm power and/or energy obligations, 

such overrun shall be billed at 10 times 

the above rate. 

For Power Factor: None. The customer 

will be required to maintain a power 

factor at the point of delivery between 

95 percent lagging and 95 percent 

leading. 

Rate Schedule P–SED–FP10 

(Supersedes Schedule P–SED–FP9) 

Effective February 1, 2009 

United States Department of Energy, 

Western Area Power Administration 

Pick-Sloan Missouri Basin Program— 

Eastern Division Montana, North 

Dakota, South Dakota, Minnesota, 

Iowa, Nebraska; 

Schedule of Rates for Firm Peaking 

Power Service 

(Approved Under Rate Order No. 

WAPA–140) 

Effective: The first day of the first full 

billing period beginning on or after 

February 1, 2009, through December 31, 

2013. 

Available: Within the marketing area 

served by the Eastern Division of the 

Pick-Sloan Missouri Basin Program, to 

customers with generating resources 

enabling them to use firm peaking 

power service. 

Applicable: To the power sold to 

customers as firm peaking power 

service. 

Character: Alternating current, 60 

hertz, three phase, delivered and 

metered at the voltages and points 

established by contract. 

Monthly Rates 

Demand Charge: $6.20 for each 

kilowatt per month (kWmonth) of the 

effective contract rate of delivery for 

peaking power or the maximum amount 

scheduled, whichever is greater. 

Energy Charge: 16.71 mills for each 

kilowatthour (kWh) for all energy 

scheduled for delivery without return. 

Charge Components 

Base: A fixed revenue requirement 

that includes operation and 

maintenance expense, investment and 

replacements, normal timing purchase 

power costs (purchases due to 

operational constraints, not associated 

with drought), and transmission costs. 

The Base peaking revenue requirement 

is $14.5 million. 

Base Demand Base Peaking Demand Revenue Requirement

Peaking = CROD Billing Units = $. / 3 40 kW month

Energy 1 = 9.27 mills/kWh 

Drought Adder: A formula-based 

revenue requirement that includes 

future purchase power above timing 

purchases, previous purchase power 

drought deficits, and interest on the 

purchase power drought deficits. For 

the period beginning February 1, 2009, 

the Drought Adder peaking revenue 

requirement is $12.0 million. 

Drought Adder Demand Drought Adder Peaking Demand Revenue = Requirement

Peaking CROD Billing Units = $. / 2 80 kW month

Energy 1 = 7.44 mills/kWh 

Process: 

Any proposed change to the Base 

component will require a public 

process. The Drought Adder component 

may be adjusted annually using the 

above formula for any costs attributed to 

drought of less than or equal to the 

equivalent of 2 mills/kWh to the Power 

Repayment Study (PRS) composite rate. 

Any planned incremental adjustment to 

the Drought Adder component greater 

than the equivalent of 2 mills/kWh to 

the PRS composite rate will require a 

public process. 

Billing Demand: The billing demand 

will be the greater of: (1) The highest 30- 

minute integrated demand measured 

during the month up to, but not in 

excess of, the delivery obligation under 

the power sales contract, or (2) the 

contract rate of delivery. 

Adjustments 

For Drought Adder: Adjustments 

pursuant to the Drought Adder 

component will be documented in a 

revision to this rate schedule. 

Billing for Unauthorized Overruns: 

For each billing period in which there 

is a contract violation involving an 

unauthorized overrun of the contractual 

obligation for peaking demand and/or 

energy, such overrun shall be billed at 

10 times the above rate. 

[FR Doc. E9–892 Filed 1–15–09; 8:45 am] 

BILLING CODE 6450–01–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

[AMS–FRL–8762–9] 

California State Nonroad Engine and 

Vehicle Pollution Control Standards; 

Authorization of Transport 

Refrigeration Unit Engine Standards, 

Notice of Decision 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Notice of Decision for 

Authorization of California Transport 

Refrigeration Unit In-use Engine 

Emission Standards. 

SUMMARY: EPA today, pursuant to 

section 209(e) of the Clean Air Act (Act), 

42 U.S.C. 7543(e), is granting California 

its request for authorization to enforce 

its Airborne Toxic Control measure 

(ATCM) establishing in-use emission 

performance standards for engines in 


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