52980 Federal Register / Vol. 73, No. 178 / Friday, September 12, 2008 / Notices 

1FERC confirmed and approved Rate Order No. 

WAPA–117 on June 13, 2006, in Docket EF05–5171. 

See United States Department of Energy, Western 

Area Power Administration, Salt Lake City 

Integrated Projects, 115 FERC ¶ 62,271 (June 13, 

2006). 

Kimberly D. Bose, 

Secretary. 

[FR Doc. E8–21151 Filed 9–11–08; 8:45 am] 

BILLING CODE 6717–01–P 

DEPARTMENT OF ENERGY 

Western Area Power Administration 

Salt Lake City Area Integrated Projects 

and Colorado River Storage Project— 

Rate Order No. WAPA–137 

AGENCY: Western Area Power 

Administration, DOE. 

ACTION: Notice of Order Concerning 

Power, Transmission, and Ancillary 

Services Rates. 

SUMMARY: The Acting Deputy Secretary 

of Energy confirmed and approved Rate 

Order No. WAPA–137 and Rate 

Schedule SLIP–F9, placing firm power 

rates for the Salt Lake City Area 

Integrated Projects (SLCA/IP) of the 

Western Area Power Administration 

(Western) into effect on an interim basis. 

The Acting Deputy Secretary also 

confirmed Rate Schedules SP–PTP7, 

SP–NW3, SP–NFT6, SP–SD3, SP–RS3, 

SP–EI3, SP–FR3, and SP–SSR3, placing 

firm and non-firm transmission rates 

and ancillary services rates on the 

Colorado River Storage Project (CRSP) 

transmission system 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 SLIP–F9, SP– 

PTP7, SP–NW3, SP–NFT6, SP–SD3, SP– 

RS3, SP–EI3, SP–FR3, and SP–SSR3 

will be placed into effect on an interim 

basis on the first day of the first full 

billing period beginning on or after 

October 1, 2008, and will be in effect 

until FERC confirms, approves, and 

places the rate schedules in effect on a 

final basis through September 30, 2013, 

or until the rate schedules are 

superseded. 

FOR FURTHER INFORMATION CONTACT: Mr. 

Bradley S. Warren, CRSP Manager, 

Colorado River Storage Project 

Management Center, Western Area 

Power Administration, 150 East Social 

Hall Avenue, Suite 300, Salt Lake City, 

UT 84111–1580, (801) 524–5493, e-mail 

warren@wapa.gov, or Ms. Carol A. 

Loftin, Rates Manager, Colorado River 

Storage Project Management Center, 

Western Area Power Administration, 

150 East Social Hall Avenue, Suite 300, 

Salt Lake City, UT 84111–1580, (801) 

524–6380, e-mail loftinc@wapa.gov. 

SUPPLEMENTARY INFORMATION: The 

Deputy Secretary of Energy approved 

Rate Order No. WAPA–117 on August 1, 

2005 (70 Fed. Reg. 47823). This Order 

included existing Rate Schedule SLIP– 

F8 for SLCA/IP firm power.1 The 

existing firm power Rate Schedule 

SLIP–F8 is being superseded by Rate 

Schedule SLIP–F9. Under Rate 

Schedule SLIP–F8, the energy rate is 

10.43 mills/kilowatthour (mills/kWh), 

and the capacity rate is $4.43/ 

kilowattmonth ($/kWmonth). The 

composite rate is 25.28 mills/kWh. The 

provisional firm power rate will be 

implemented over a 2-year period. In 

the first year, the provisional firm power 

rate consists of an energy charge of 

11.06 mills/kWh and a capacity charge 

of $4.70/kWmonth. The second step of 

the rate will be effective October 1, 

2009, and will be capped at the energy 

charge of 12.29 mills/kWh and a 

capacity charge of $5.22/kWmonth. The 

provisional rates for SLCA/IP firm 

power in Rate Schedule SLIP–F9 will 

result in an overall composite rate of 

26.80 mills/kWh on October 1, 2008, 

and a composite rate capped at 29.68 

mills/kWh on October 1, 2009, through 

September 30, 2013, or until 

superseded. This second step rate 

adjustment will result in an overall 

increase of about 17.4 percent when 

compared with the existing SLCA/IP 

firm power composite rate under Rate 

Schedule SLIP–F8. 

The firm power rate will continue to 

include a cost recovery mechanism 

called the Cost Recovery Charge (CRC). 

The CRC is necessary to adequately 

maintain a sufficient cash balance in the 

Upper Colorado River Basin Fund. The 

CRC is a charge on Sustainable 

Hydropower (SHP) energy, as 

determined by financial conditions. 

Every May, Western will provide 

customers with information concerning 

any anticipated CRC for the upcoming 

fiscal year (FY). If Western determines 

a CRC is necessary, firm power 

customers may choose not to take as 

much firm energy and, in exchange, 

Western will waive the CRC charge. In 

addition to the potential for a CRC being 

implemented every year, Western will 

consider assessing the CRC upon a 45- 

day notice to customers, should water 

releases at Glen Canyon Dam be reduced 

to less than 8.23 million acre-feet (MAF) 

in a FY. 

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 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 00–001.00A, 10 CFR part 

903, and 18 CFR part 300, I hereby 

confirm, approve, and place Rate Order 

No. WAPA–137, the proposed SLCA/IP 

firm power rate, CRSP firm and nonfirm transmission rates, and ancillary 

services rates into effect on an interim 

basis. 

The new Rate Schedules SLIP–F9, 

SP–PTP7, SP–NW3, SP–NFT6, SP–SD3, 

SP–RS3, SP–EI3, SP–FR3, and SP–SSR3 

will be promptly submitted to FERC for 

confirmation and approval on a final 

basis. 

Dated: September 4, 2008. 

Jeffrey F. Kupfer, 

Acting Deputy Secretary. 

Department of Energy 

Deputy Secretary 

[Rate Order No. WAPA–137] 

In the Matter of: Western Area Power 

Administration Rate Adjustment for the Salt 

Lake City Area Integrated Projects and 

Colorado River Storage Project; Order 

Confirming, Approving, and Placing the Salt 

Lake City Area Integrated Projects Firm 

Power, Colorado River Storage Project 

Transmission and Ancillary Services Rates 

Into Effect on an Interim Basis 

These rates 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 (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 other acts that 

specifically apply to the project 

involved. 

By Delegation Order No. 00–037.00, 

effective December 6, 2001, the 


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Federal Register / Vol. 73, No. 178 / Friday, September 12, 2008 / Notices 52981 

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 Federal 

Energy Regulatory Commission (FERC). 

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. 

A.F.: Acre-feet. 

AFC: Actual firming energy costs (MWh) 

as used in the PYA formula. 

AHP: Available Hydropower. 

ALP: Animas La Plata Project. 

ATRR: Annual Transmission Revenue 

Requirement. 

Basin Fund: Upper Colorado River 

Basin Fund. 

BFBB: Basin Fund Beginning Balance as 

used in the CRC formula. 

BFTB: Basin Fund Target Balance as 

used in the CRC formula. 

Capacity: The electric capability of a 

generator, transformer, transmission 

circuit, or other equipment. It is 

expressed in kW. 

Capacity Rate: The rate which sets forth 

the charges for capacity. It is 

expressed in $/kWmonth and applied 

to each kW of the Contract Rate of 

Delivery (CROD). 

CDP: Customer Displacement Power. 

Composite Rate: The rate for 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/kWh 

and used for comparison purposes. 

CRC: Cost Recovery Charge. A 

mechanism to assist in recovery of 

purchased power costs during 

financial hardship. 

CRCE: CRC Energy (GWh) as used in the 

CRC and PYA formulas. 

CRCEP: CRC Energy Percentage of full 

SHP as used in the CRC and PYA 

formulas. 

CROD: Contract Rate of Delivery. The 

maximum amount of capacity made 

available to a preference customer for 

a period specified under a contract. 

CRSP: Colorado River Storage Project. 

CRSP Act: An act to authorize the 

Secretary of the Interior to construct, 

operate, and maintain the Colorado 

River Storage Project and 

Participating Projects, and for other 

purposes. (Act of April 11, 1956, ch. 

203, 70 Stat. 105) 

CRSP MC: The CRSP Management 

Center of Western Area Power 

Administration. 

Customer: An entity with a contract that 

is receiving firm electric service and 

transmission from Western’s CRSP 

MC. 

DOE: United States Department of 

Energy. 

DOE Order RA 6120.2: An order 

outlining power marketing 

administration financial reporting and 

ratemaking procedures. 

DSW: Desert Southwest Region of 

Western Area Power Administration. 

EA: SHP Energy Allocation (GWh) as 

used in the CRC formula. 

EAC: Sum of customers’ energy 

allocations subject to the PYA 

formula. 

Energy: Power produced or delivered 

over a period of time. It is expressed 

in kilowatthours. 

Energy Rate: The rate which sets forth 

the charges for energy. It is expressed 

in mills/kWh and applied to each 

kWh delivered to each Customer. 

EIS: Environmental Impact Statement. 

FA: Funds Available as used in the CRC 

formula. 

FA1: Basin Fund Balance Factor as used 

in the CRC formula. 

FA2: Revenue Factor as used in the CRC 

formula. 

FARR: Additional revenue to be 

recovered as used in the CRC formula. 

FE: Forecasted purchased energy as 

used in the CRC formula. 

FERC: Federal Energy Regulatory 

Commission. 

FFC: Forecasted average energy price 

per MWh as used in the CRC and PYA 

formulas. 

Firm: A type of product and/or service 

always available at the time requested 

by the customer. 

FRN: Federal Register notice. 

FX: Forecasted energy purchased 

expense as used in the CRC formula. 

FY: Fiscal year is the period from 

October 1 to September 30. 

GWh: Gigawatthour. The electrical unit 

of energy that equals 1 billion watthours or 1 million kWh. 

HE: Forecasted hydro energy as used in 

the CRC formula. 

Integrated Projects: The resources and 

revenue requirements of the Collbran, 

Dolores, Rio Grande, and Seedskadee 

projects blended together with the 

CRSP to create the SLCA/IP resources 

and rate. 

kW: Kilowatt. The electrical unit of 

capacity that equals 1,000 watts. 

kWh: Kilowatthour. The electrical unit 

of energy that equals 1,000 watts 

produced or delivered in 1 hour. 

kWmonth: Kilowattmonth. The 

electrical unit of the monthly amount 

of capacity. 

kWyear: Killowattyear. A unit of 

electrical capacity demanded for 

8,760 hours. 

Load: The amount of electric power or 

energy delivered or required at any 

specified point(s) on a system. 

Load-Ratio Share: Network customer’s 

hourly load (including its designated 

network load not physically 

interconnected with Western) 

coincident with Western’s monthly 

CRSP transmission system peak. 

M&I: Municipal and Industrial water. 

MAF: Million Acre-Feet. The amount of 

water required to cover 1 million 

acres, 1 foot in depth. 

Mill: A monetary denomination of the 

United States that equals one-tenth of 

a cent or one-thousandth of a dollar. 

Mills/kWh: Mills per kilowatthour. A 

unit of charge for energy. 

MW: Megawatt. The electrical unit of 

capacity that equals 1 million watts or 

1,000 kilowatts. 

MWh: One million watt-hours of electric 

energy. A unit of electrical energy 

which equals 1 megawatt of power 

used for 1 hour. 

NATRR: Net Annual Transmission 

Revenue Requirement. 

NB: Net Balance as used in the CRC 

formula. 

NEPA: National Environmental Policy 

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

Non-firm: A type of product and/or 

service not always available at the 

time requested by the customer. 

NR: The net revenue remaining after 

paying all annual expenses as used in 

the CRC formula. 

OASIS: Open Access Same-Time 

Information System. 

O&M: Operation and Maintenance. 

OM&R: Operation, Maintenance, and 

Replacements. 

PAE: Projected Annual Expenses as 

used in the CRC formula. 

PAR: Projected Annual Revenue 

without the CRC as used in the CRC 

formula. 

Participating Projects: The projects 

participating with CRSP according to 

the CRSP Act of 1956 (43 U.S.C. 620). 

PFE: Prior year actual firming energy as 

used in the PYA formula. 

PFX: Prior year actual firming expenses 

as used in the PYA formula. 

Pinch Point: The nearest future year in 

the PRS where cumulative expenses 

and required payments equal 

cumulative revenues. 

Power: Capacity and energy. 

Preference: The provisions of 

Reclamation Law which require 

Western to first make Federal power 

available to certain entities. For 


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52982 Federal Register / Vol. 73, No. 178 / Friday, September 12, 2008 / Notices 

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. 

Price: Average price per MWh for 

purchased power as used in the CRC 

formula. 

Project Use: Power used to operate the 

CRSP Participating Projects facilities 

under Reclamation Law. 

Proposed Rate: A rate that has been 

recommended by Western to the 

Deputy Secretary of DOE for approval. 

Provisional Rate: A rate which has been 

confirmed, approved, and placed into 

effect on an interim basis by the 

Deputy Secretary of DOE. 

PRS: Power Repayment Study. 

PYA: Prior Year Adjustment as used in 

the CRC formula. 

RA: Revenue Adjustment as used in the 

PYA formula. 

Rate Brochure: A document explaining 

the rationale and background for the 

rate proposal contained in this Rate 

Order, dated January 2008. 

Ratesetting PRS: The PRS used for the 

rate adjustment proposal. 

Reclamation: United States Department 

of the Interior, Bureau of Reclamation. 

Reclamation Law: A series of Federal 

laws, viewed as a whole that create 

the originating framework under 

which Western markets power. 

Revenue Requirement: The revenue 

required to recover annual expenses, 

such as O&M, purchased power, 

transmission service expenses, 

interest, deferred expenses, 

repayment of Federal investments, 

and other assigned costs. 

RMR: Rocky Mountain Region of 

Western Area Power Administration. 

SHP: Sustainable Hydropower as 

defined in the firm power contracts 

for SLCA/IP. 

SLCA/IP: Salt Lake City Area Integrated 

Projects. The resources and revenue 

requirements of the Collbran, Dolores, 

Rio Grande, and Seedskadee projects 

blended together with the CRSP to 

create the SLCA/IP rate. 

Supporting Documentation: A 

compilation of data and documents 

that support the Rate Brochure and 

the rate proposal. 

TRC: Transmission Revenue Credits. 

TSTL: CRSP Transmission System Total 

Load. 

Western: United States Department of 

Energy, Western Area Power 

Administration. 

WL: Waiver Level as used in the CRC 

formula. 

WLP: Waiver Level Percentage of full 

SHP as used in the CRC formula. 

WPR: Work Program Review. The work 

plan is a draft estimate of costs that 

are expected to be included in the 

Congressional Budget for Western and 

Reclamation and the basis for budget 

estimates to be used in the PRS. 

WRP: Western Replacement Power as 

defined in the firm power contracts 

for SLCA/IP. 

Effective Date 

The new interim rates will take effect 

on the first day of the first full billing 

period beginning on or after October 1, 

2008, and will remain in effect until 

September 30, 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 May 30, 2007, when 

Western mailed a notice announcing an 

informal customer meeting on June 19, 

2007, to all SLCA/IP customers and 

interested parties. 

2. On June 19, 2007, August 21, 2007, 

and October 10, 2007, beginning at 

10:30 a.m., informal customer meetings 

were held to discuss the components 

and rationale for the rate adjustment, to 

discuss possible rate designs, and to 

answer questions. 

3. A Federal Register notice, 

published on January 4, 2008 (73 FR 

858), announced the proposed rate 

adjustments for the SLCA/IP, CRSP 

Transmission, and Ancillary Services 

Rates. This publication began a public 

consultation and comment period and 

announced the public information and 

public comment forums. 

4. On January 11, 2008, Western’s 

CRSP MC mailed all SLCA/IP 

preference customers, CRSP 

transmission customers, and interested 

parties letters along with the Rate 

Brochure, which contains a copy of the 

published Federal Register notice 

proposal and a reminder of the February 

5, 2008, public information forum. 

5. On February 5, 2008, beginning at 

1:30 p.m., Western held a public 

information forum at the Radisson Hotel 

Salt Lake City Airport, Salt Lake City, 

Utah. Western provided detailed 

explanations of the proposed SLCA/IP 

firm power rate and the CRSP 

transmission and ancillary service rates. 

Western provided Rate Brochures, 

supporting documentation, and 

informational handouts at this meeting. 

6. On March 4, 2008, beginning at 

1:30 p.m., Western held a comment 

forum at the Radisson Hotel Salt Lake 

City Airport, Salt Lake City, Utah, to 

give the public an opportunity to 

comment for the record. Western also 

notified its customers of its intent to 

extend the comment and consultation 

period through May 5, 2008, and to hold 

additional information and comment 

forums. 

7. On March 12, 2008, Western’s 

CRSP MC mailed a flyer to all SLCA/IP 

customers, CRSP transmission 

customers, and interested parties 

notifying them of a second public 

information forum and a second 

comment forum. 

8. A Federal Register notice, 

published March 24, 2008 (73 FR 

15519), announced the extension of the 

comment and consultation period for 

the SLCA/IP firm power, CRSP 

transmission and ancillary services 

rates. 

9. On March 24, 2008, CRSP MC 

mailed all SLCA/IP customers, CRSP 

transmission customers, and interested 

parties a letter with a copy of the 

published FRN extending the comment 

and consultation period for the SLCA/ 

IP firm power, CRSP transmission and 

ancillary services rates. 

10. On April 10, 2008, beginning at 

1:30 p.m., Western held its second 

public information forum at the Bureau 

of Reclamation, Wallace F. Bennett 

Federal Building, Room 8102, 125 South 

State Street, Salt Lake City, Utah. 

11. On April 10, 2008, beginning at 

2:35 p.m., Western held its second 

comment forum at the Bureau of 

Reclamation, Wallace F. Bennett Federal 

Building, Room 8102, 125 South State 

Street, Salt Lake City, Utah. 

12. Western received 17 comment 

letters during the consultation and 

comment period, which ended May 5, 

2008. All formally submitted comments 

have been considered in preparing this 

Rate Order. 

Comments 

Written comments were received from 

the following organizations: 

Arizona Tribal Energy Association, 

Arizona (2), 

Farmington Electric Utility System, New 

Mexico, 

Colorado River Energy Distributors 

Association, Arizona (3), 

Grand Canyon Trust, Arizona, 

Inter Tribal Council of Arizona, Inc., 

Arizona, 

Irrigation & Electrical Districts 

Association of Arizona, Arizona, 

Living Rivers, Utah (2), 


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Murray City Corporation, Utah (2), 

Navajo Tribal Utility Authority, 

Arizona, 

Salt River Pima-Maricopa Indian 

Community, Arizona, 

Utah Associated Municipal Power 

Systems, Utah, 

Yavapai-Apache Nation, Arizona. 

Representatives of the following 

organizations made oral comments: 

Arizona Tribal Energy Association, 

Arizona, Colorado River Energy 

Distributors Association, Arizona, 

Navajo Tribal Utility Authority, 

Arizona, 

Utah Associated Municipal Power 

Systems, Utah. 

Project Description 

The SLCA/IP consists of the CRSP, 

Rio Grande, and Collbran projects. The 

CRSP includes two participating 

projects that have power facilities: the 

Dolores and Seedskadee projects. 

Western integrated the Rio Grande and 

Collbran projects with CRSP for 

marketing and ratemaking purposes on 

October 1, 1987. The goals of integration 

were to increase marketable resources, 

simplify contract and rate development 

and project administration by creating 

one rate and to ensure repayment of the 

Projects’ costs. All Integrated Projects 

maintain their individual identities for 

financial accounting and repayment 

purposes, but their revenue 

requirements are integrated into the 

SLCA/IP PRS for ratemaking. 

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 SLCA/IP. 

Repayment criteria are based on policies 

(including DOE Order RA 6120.2) and 

authorizing law. 

Provisional rates for SLCA/IP firm 

power result in an overall composite 

rate increase of approximately 17.4 

percent, when compared to the existing 

SLCA/IP firm power rates in Rate 

Schedule SLIP–F8. The current 

composite rate under Rate Schedule 

SLIP–F8 is 25.28 mills/kWh. The 

provisional rates for SLCA/IP firm 

power in Rate Schedule SLIP–F9 will be 

implemented over a 2-year period 

resulting in a composite rate of 26.80 

mills/kWh on October 1, 2008, and a 

composite rate capped at 29.68 mills/ 

kWh on October 1, 2009. In the first 

year, the provisional firm power rate 

consists of an energy charge of 11.06 

mills/kWh and a capacity charge of 

$4.70/kWmonth. The second step of the 

rate will be effective October 1, 2009 

through September 30, 2013, or until 

superseded. The energy charge will not 

exceed 12.29 mills/kWh and the 

capacity charge will not exceed $5.22/ 

kWmonth. The actual rates for the 

second step will be determined using 

2008 actual data, updated estimates for 

purchased power and transmission, as 

well as other revised estimates that 

could affect the rate. Western will 

provide customers an opportunity to 

comment on the second step during a 

meeting scheduled for June 2009. The 

following table compares the current 

and proposed firm power rates. 

COMPARISON OF CURRENT AND PROPOSED FIRM POWER RATES

Current rate 

October 1, 2005– 

September 30, 

2010 

Proposed rate 

October 1, 2008 

(1st step) 

Percent 

increase 

for 1st 

step 

Proposed rate1

October 1, 2009– 

September 30, 

2013 

(2nd step) 

Total 

percent 

increase 

Rate Schedule ............................................................ SLIP–F8 ................. SLIP–F9 ................. ................ SLIP–F9 ................. ................

Energy (mills/kWh) ...................................................... 10.43 ...................... 11.06 ...................... 6.0 12.29 ...................... 17.8 

Capacity ($/kWmonth) ................................................ 4.43 ........................ 4.70 ........................ 6.0 5.22 ........................ 17.9 

Composite Rate (mills/kWh) ....................................... 25.28 ...................... 26.80 ...................... 6.0 29.68 ...................... 17.4 

1 Maximum rate for FY 2010. 

Cost Recovery Charge 

Western is proposing to continue the 

CRC calculation and assessment in the 

proposed rate schedule as it is in the 

current SLIP–F8 rate schedule and to 

add an additional triggering mechanism. 

The CRC is based on a Basin Fund 

cash analysis only and is independent 

of the PRS calculations. In the event that 

expenses significantly exceed estimates 

and in order to adequately recover and 

maintain a sufficient balance in the 

Basin Fund, Western will calculate and 

assess a CRC. The CRC is designed to 

maintain a Basin Fund Target Balance 

(BFTB) for the following FY and to limit 

the FY loss to the Basin Fund. The 

BFTB will be equal to 15 percent of the 

upcoming FY’s total expenses but not 

less than $20 million. The allowable FY 

loss is limited to no more than 25 

percent of the Basin Fund Beginning 

Balance (BFBB). For purposes of 

explaining how the CRC is calculated, 

please refer to Rate Schedule SLIP–F9. 

Trigger for Shortage Criteria 

In the event that Reclamation’s 24- 

month study projects that Glen Canyon 

Dam water releases will drop below 8.23 

MAF in a water year (October through 

September), Western will recalculate the 

CRC to include those lower estimates of 

hydropower generation and the 

estimated costs for any additional 

purchased power. Western, as in the 

yearly projection for the CRC, will give 

the customers a 45-day notice, during 

which they may request a waiver of the 

CRC by voluntarily taking less energy 

than allowed under the customer’s Firm 

Electric Service contract. This 

recalculation will remain in effect for 

the remainder of the current FY. In the 

event that hydropower generation 

returns to 8.23 MAF or higher during 

the CRC implementation, a new CRC 

will be calculated for the next month, 

and the customers will be notified. 

Narrative PYA Discussion 

Since the annual determination of the 

CRC is based upon estimates, an annual 

prior year adjustment (PYA) will be 

calculated. The CRC PYA for 

subsequent years will be determined by 

comparing the prior year’s estimated 

firming energy cost to the prior year’s 

actual firming energy cost for the energy 

provided above the Waiver Level. The 

PYA will result in an increase or 

decrease to a customer’s firm energy 

costs over the course of the following 

year. Please see Rate Schedule SLIP-F9 

rate schedule for further explanation of 

the PYA calculation. 

CRC Schedule for Customers 

Western will provide its customers 

with information concerning the 

anticipated CRC for the upcoming FY in 

May. The established CRC will be in 

effect for the entire FY. The table below 

displays the time frame for determining 

the amount of purchases needed, 


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developing customer’s load schedules, 

and making purchases. 

CRC SCHEDULE

Task Date1

April 24-Month Study (Forecast 

to Model Projections).

April 1. 

CRC Notice to Customers ......... May 1. 

Waiver Request Submitted by 

Customers.

June 15. 

CRC Effective ............................ October 1. 

1 Note: This schedule does not apply if the 

CRC is triggered by the Glen Canyon Dam 

annual releases dropping below 8.23 MAF. 

CRSP Transmission Rates Discussion 

The proposed firm and non-firm 

transmission rates apply to all 

transmission-only sales. The present 

CRSP point-to-point, network, and nonfirm transmission rates, outlined in Rate 

Schedules SP–PTP6, SP–NW2, and SP– 

NFT5 became effective on October 1, 

2002. On June 29, 2007, the Deputy 

Secretary of Energy extended the 

transmission rates through September 

30, 2010. The transmission rates include 

the cost for scheduling, system control, 

and dispatch service. Western is 

proposing that these three rates remain 

in effect for this new ratesetting period. 

The cost of transmission service for 

Western’s SLCA/IP long-term electric 

service will continue to be included in 

the SLCA/IP firm power rate. 

Transmission services are outlined in 

Western’s Tariff. 

Western is proposing to use the 

current methodology, which is an 

annual fixed charge formula, to 

determine the revenue requirement to 

be recovered from firm and non-firm 

transmission service. The annual 

transmission revenue requirement 

includes O&M expenses, administrative 

and general expenses, interest expense, 

and depreciation expense. This 

methodology is updated annually using 

a test year, which is the most recent 

historical data available. This revenue 

requirement is offset by appropriate 

CRSP transmission system revenues. 

The provisional rate for network 

transmission service is a formula 

calculation based on the annual 

transmission revenue requirement. 

There are no changes to the existing 

network integration transmission 

service formula under Rate Schedule 

SP–NW2. 

Firm Point-to-Point 

Western is seeking the continued 

approval of a rate formula for 

calculation of the firm point-to-point 

transmission rate to be applied 

annually. The provisional rate for firm 

point-to-point transmission service is 

$2.21/kWmonth for FY 2008. 

The firm point-to-point transmission 

rate is based upon the most recent 

historical year, using an annual fixedcharge methodology. The annual 

transmission revenue requirement is 

reduced by revenue credits such as nonfirm transmission, existing contracts at 

different rates, scheduling and dispatch 

services, and phase-shifter revenues. 

The resultant net annual transmission 

revenue requirement is divided by the 

capacity reservation needed to meet 

firm power and transmission-only 

commitments in kW, including the total 

network integration loads at system 

peak, to derive a cost/kWyear. The 

formula is updated every year by 

applying the most current historical test 

year. If needed, a revised rate will 

become effective every October 1. The 

rate formula is proposed to be effective 

October 1, 2008, through September 30, 

2013. 

The cost/kWyear is calculated using 

the following formula: 

(1) ATRR − = TRC NATRR

NATRR

TSTL ( ) 2

Where: 

ATRR = Annual Transmission Revenue 

Requirement. The costs associated with 

facilities that support the transfer 

capability of the CRSP transmission 

system, excluding generation facilities. 

These costs include investment costs, 

interest expenses, depreciation expense, 

administrative and general expenses, and 

operation and maintenance expense, 

including transmission purchases. 

Transmission purchases reflect those 

costs associated with CRSP contractual 

rights. 

TRC = Transmission Revenue Credits. The 

revenues generated by the CRSP 

transmission system not related to the 

revenues from the sale of long-term firm 

transmission. 

NATRR = Net Annual Transmission Revenue 

Requirement. The Annual Revenue 

Requirement minus Transmission 

Revenue Credits. 

TSTL = CRSP Transmission System Total 

Load. The sum of the total CRSP 

transmission capacity under long-term 

reservation including the total network 

integration loads at system peak. 

Non-Firm Point-to-Point Transmission 

The proposed rate for non-firm pointto-point CRSP transmission service is a 

mills/kWh rate, which is based upon the 

current firm point-to-point rate and may 

be discounted. This rate will remain in 

effect concurrently with the firm pointto-point rate and will also be reviewed 

annually. Transmission availability will 

be posted on Western’s OASIS. 

Network Transmission 

The proposed rate for network 

transmission is a calculation based upon 

the annual revenue requirement then in 

effect, as determined by the annual 

fixed charge methodology. 

Ancillary Services Discussion 

Six ancillary services will continue to 

be offered by CRSP MC, two of which 

are required as part of CRSP 

transmission service. These are (1) 

Scheduling, system control, and 

dispatch service and (2) reactive supply, 

and voltage control service. The 

remaining four ancillary services are (3) 

regulation and frequency response 

service, (4) energy imbalance service, (5) 

spinning reserve service, and (6) 

supplemental reserve service. These 

will be offered either from the balancing 

authority or from the CRSP MC 

Merchant Function. Sales of regulation 

and frequency response, energy 

imbalance, spinning reserve, and 

supplemental reserve services from 

SLCA/IP power resources are limited 

since Western has allocated the SLCA/ 

IP power resources to preference entities 

under long-term commitments. Western 

has made a clarification to its spinning 

and supplemental reserve ancillary 

services and has removed its reference 

to the Western System Power Pool 

Agreement. Western will continue to 

use market-based rates to determine its 

rate for spinning and supplemental 

reserves under the Rate Schedule SSP– 

SSR3. The availability and type of 

ancillary service will be determined 

based on excess resources available at 

the time the services are requested, 

except for the two ancillary services 

required to be provided in conjunction 

with the sale of CRSP transmission 

services. 

Since the CRSP transmission system 

lies in two balancing authorities, 

operated by Western’s RMR and DSW, 

many of the ancillary services are 

offered through their respective 

balancing authorities. 

The provisional rates for ancillary 

services are designed to recover only the 

costs associated with providing the 

service(s). The costs for providing 

scheduling, system control, and 

dispatch service are included in the 

appropriate provisional transmission 

services rates. However, the charges for 

reactive supply and voltage control 

service will be in accordance with 

Western’s RMR and DSW applicable 

rate schedules. 

Existing and Provisional Rates 

A comparison of the existing and 

provisional SLCA/IP firm power rates, 


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CRSP Transmission and Ancillary 

Services, follows: 

COMPARISON OF EXISTING AND PROVISIONAL SALT LAKE CITY AREA INTEGRATED PROJECTS FIRM POWER, COLORADO

RIVER STORAGE PROJECT TRANSMISSION AND ANCILLARY SERVICES

Current rate 

October 1, 2005– 

September 30, 2010 

Provisional rate 

October 1, 2008 

(1st step) 

Percent increase 

for 1st step 

Provisional rate1

October 1, 2009– 

September 30, 2013 

(2nd step) 

Total percent 

increase 

Energy (mills/kWh) ................... 10.43 ...................... 11.06 ...................... 6 ............................. 12.29 ...................... 17.8. 

CRC (if applicable) .................. varies ...................... varies ...................... varies ...................... varies ...................... varies. 

Capacity ($/kWmonth) ............. 4.43 ........................ 4.70 ........................ 6 ............................. 5.22 ........................ 17.9. 

Composite Rate (mills/kWh) .... 25.28 ...................... 26.80 ...................... 6 ............................. 29.68 ...................... 17.4. 

Firm Transmission Rate .......... $2.21 (FY 08) ......... To be determined 

for FY 09.

To be determined 

for FY 09.

To be determined 

for FY 10.

To be determined 

for FY 10. 

Network Transmission (net annual revenue requirement).$72,613,170 (FY 

08).

To be determined 

for FY 09.

To be determined 

for FY 09.

To be determined 

for FY 10.

To be determined 

for FY 10. 

Non-firm Transmission Rate .... 3.03 mills/kWh, may 

be discounted 

(FY 08).

To be determined 

for FY 09.

To be determined 

for FY 09.

To be determined 

for FY 10.

To be determined 

for FY 10. 

Ancillary Services 2 .................. N/A ......................... N/A ......................... N/A ......................... N/A ......................... N/A. 

1 Maximum rate for FY 2010–2013. 

2Since all of CRSP transmission facilities are located in two Western balancing authorities, these services are provided through these balancing authorities. 

Certification of Rates 

Western’s Administrator certified that 

the provisional rates for SLCA/IP firm 

power, CRSP transmission, and 

ancillary services are the lowest 

possible rates consistent with sound 

business principles. The provisional 

rates were developed following 

administrative policies and applicable 

laws. 

SLCA/IP Firm Power Rate Discussion 

According to Reclamation Law, 

Western must establish power rates 

sufficient to recover O&M expenses, 

purchased power expenses, interest 

expenses, and repayment of power 

investment and irrigation aid. 

The existing rate for SLCA/IP firm 

power under Rate Schedule SLIP–F8 

expires September 30, 2010. Effective 

October 1, 2008, Rate Schedule SLIP–F8 

will be superseded by the new rates in 

Rate Schedule SLIP–F9. The provisional 

rates for SLCA/IP firm power consist of 

a capacity rate and an energy rate. The 

provisional rates for SLCA/IP firm 

power in Rate Schedule SLIP–F9 will 

result in a composite rate of 26.80 mills/ 

kWh on October 1, 2008, and a 

composite rate capped at 29.68 mills/ 

kWh on October 1, 2009. The 

provisional firm power rate will be 

implemented over a 2-year period. In 

the first year, the provisional firm power 

rate consists of an energy charge of 

11.06 mills/kWh and a capacity charge 

of $4.70/kWmonth. The second step of 

the rate will be effective October 1, 

2009, through September 30, 2013, or 

until superseded, and will be capped at 

the energy charge of 12.29 mills/kWh 

and a capacity charge of $5.22/ 

kWmonth. 

Statement of Revenue and Related 

Expenses 

The following table provides a 

summary of projected revenue and 

expense data for the SLCA/IP firm 

power rate through the 5-year 

provisional rate approval period. 

SLCA/IP FIRM POWER—COMPARISON OF 5-YEAR RATE PERIOD (FY 2009–FY 2013) TOTAL REVENUES AND EXPENSES

[$000] 

Existing rate 

Proposed 

rate with 

cap 

Difference 

Total revenues ....................................................................................................................................... 828,785 919,125 90,340 

Revenue Distribution 

Expenses: 

O&M ................................................................................................................................................ 314,501 348,731 34,230 

Purchased Power and Transmission ............................................................................................. 76,489 133,525 57,036 

Integrated Projects Requirements .................................................................................................. 38,820 37,733 (1,087 ) 

Interest ............................................................................................................................................ 33,165 67,551 34,386 

Other ............................................................................................................................................... 17,789 14,784 (3,005 ) 

Total Expenses ........................................................................................................................ 480,764 602,324 121,560 

Principal Payments: 

Capitalized Expenses (deficits) ...................................................................................................... 0 0 0 

Original Project and Additions ........................................................................................................ 198,009 96,812 (101,197 ) 

Replacements ................................................................................................................................. 137,183 206,803 69,620 

Irrigation .......................................................................................................................................... 12,829 13,186 357 

Irrigation to Participating Projects .................................................................................................. 0 0 0 

Total Principal Payments ........................................................................................................ 348,021 316,801 (31,220 ) 


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SLCA/IP FIRM POWER—COMPARISON OF 5-YEAR RATE PERIOD (FY 2009–FY 2013) TOTAL REVENUES AND

EXPENSES—Continued 

[$000] 

Existing rate 

Proposed 

rate with 

cap 

Difference 

Total Revenue Distribution ............................................................................................... 828,785 919,125 90,340 

Basis for Rate Development 

The existing rates for SLCA/IP firm 

power in Rate Schedule SLIP–F8 no 

longer provide sufficient revenues to 

pay all annual costs, including interest 

expense, and repayment of investment 

and irrigation aid within the allowable 

periods. The adjusted rates reflect 

increases primarily in O&M costs and 

purchased power and transmission 

costs. The provisional rates will provide 

sufficient revenue to pay all annual 

costs, including interest expense, and to 

repay power investment and irrigation 

aid within the allowable periods. To 

coincide with the start of each FY, the 

provisional rates for the first step will 

take effect on October 1, 2008. The 

provisional rates for the second step 

will take effect on October 1, 2009, and 

remain in effect through September 30, 

2013. 

Provisions for transformer losses 

adjustment, power factor adjustment, 

WRP administrative charge, and CDP 

administrative charge adjustments are 

part of the provisional rates for SLCA/ 

IP firm power. Western will not modify 

the provisions and methodologies for 

these adjustments, which will remain as 

specified in Rate Schedule SLIP–F9. 

Comments 

The comments and responses 

regarding the firm power rate, 

paraphrased for brevity when not 

affecting the meaning of the 

statement(s), are discussed below. Direct 

quotes from comment letters are used 

for clarity where necessary. The rate 

process issues discussed are (1) Firm 

Power Rate Design, (2) Cost Recovery 

Charge, (3) Stepped Rate, (4) Basin 

Fund, (5) Revenue, (6) Western 

Expenses, (7) Reclamation Expenses and 

Related Issues, (8) Project Use, (9) 

Environmental, (10) Hydrology, (11) 

Transmission and Ancillary Services, 

and (12) Miscellaneous. 

1. Firm Power Rate Design 

Comment: Many customers expressed 

appreciation for the CRSP MC and its 

willingness to engage in meaningful 

dialogue, entertain suggestions, and 

develop alternatives to mitigate 

significant rate increases. 

Response: The CRSP MC is likewise 

appreciative of the customers’ support. 

Comment: Pages 6 and 8 of the Rate 

Brochure reference the ‘‘ratesetting 

period’’ of 17 years as opposed to 20 

years. Please explain why a different 

ratesetting period was used. Are the 

current rates in effect based upon a 20- 

year ratesetting period? 

Response: The current rate is based on 

a 20-year ratesetting period. The 

ratesetting period begins the year the 

rate took effect (FY 2006) and continues 

through the pinch point year (FY 2025). 

The pinch point year is the year of the 

PRS that has the largest revenue 

requirements. 

The proposed rate will take effect in 

October 2008, which is the beginning of 

FY 2009. Since the proposed ratesetting 

period extends through the same pinch 

point year, the ratesetting period of the 

proposed rate is 3 years shorter than 

that of the current rate. 

Comment: Some customers requested 

copies of all documents and information 

used to develop the cost basis for the 

O&M component of the new rate 

included in the PRS. 

Response: Documents and 

information used to develop the cost 

basis for the O&M component of the rate 

proposal were included in the 

Supporting Documentation Booklet, 

specifically Tab 10, which had been 

previously provided to requestors. In 

addition, the requestors were sent 

copies of the CRSP MC Work Program 

Review documents for FY 2006 through 

FY 2010. 

Comment: One commenter asked 

Western to explain on what basis 

Western could extend the collection of 

revenues for apportionment such that 

rate impacts of those obligations are 

reduced. 

Response: Western adheres 

specifically to section 5(e) of the CRSP 

Act, which requires the inclusion of the 

apportionment of revenues for the 

States, in the Power Repayment Studies. 

In addition, DOE Order RA6120.2 

provides further clarification of the 

treatment of repayment periods, 

specifically in section 12(b)(5), which 

states ‘‘expected revenues are at least 

sufficient to recover other costs such as 

payments to basin funds, Participating 

Projects or States.’’ 

Comment: One commenter asked 

Western, ‘‘Please run the PRS and 

provide the results excluding the funds 

categorized as ‘Available w/Appor’ 

found behind Tab 19 of the CRSP MC 

Supporting Documentation for Proposed 

Rates: SLCA/IP Firm Power, CRSP 

Transmission & Ancillary Services dates 

January 2008 on the sheet titled 

‘Colorado River Storage Project, Aid to 

Participating Projects Irrigation 

Repayment Obligations and 

Apportioned Revenue Applied’ totaling 

$642,582,791, which are not tied to 

authorized projects.’’ 

Response: The proposed rate includes 

the apportionment revenues required to 

be collected through FY 2025 (about 

$368 million). The PRS was rerun 

without the excess revenue collection 

for apportionment required by the CRSP 

Act. Removing these apportionment 

collections from the repayment period 

lowered the composite rate by 2.61 

mills/kWh. 

Comment: Multiple comments were 

received concerning the inclusion of 

apportionment revenue collection in the 

rate, mentioning that $368 million of 

revenues for apportionment payments 

would be received by FY 2025. The 

customers objected to the inclusion of 

these apportionment revenues in the 

ratesetting period and recommended 

that apportionment costs associated 

with unauthorized, unconstructed 

projects be programmed into the PRS 

beyond the pinch point year. 

Response: Section 5(e) of the CRSP 

Act specifies that revenues in the Basin 

Fund in excess of the amounts needed 

to defray the cost of operation, 

maintenance and replacement of the 

CRSP Project, and to return to the 

general fund of the Treasury costs 

allocated to power, municipal water 

supply, irrigation and salinity control 

shall be apportioned to the four Upper 

Colorado Basin States to assist in the 

repayment of participating projects 

located within these States. Section 5(e) 

specifies that such excess ‘‘revenues in 

the Basin Fund * * * shall be 

apportioned among the states of the 

Upper Division in the following 

percentages: Colorado, 46 per centum; 


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Utah, 21.5 per centum; Wyoming, 15.5 

per centum; and New Mexico, 17 per 

centum * * *.’’ Funds so apportioned 

must be used only for the repayment of 

construction costs of participating units 

located in the states to which such 

revenues are apportioned. 

Comment: A commenter stated that 

approximately 60 percent of the 

proposed rate increase appears to be due 

to apportionment expenses associated 

with presently non-existent, 

unauthorized projects. 

Response: The comment correctly 

observes that removing the 

apportionment obligation from the 

proposed rate would reduce the 

proposed rate increase by approximately 

60 percent; however, as discussed 

above, the apportionment obligation is 

required by law, and as such, the 

apportionment obligations are already 

included in the current rate and 

therefore play no part in the proposed 

17 percent increase. The 17 percent 

increase is due mainly to O&M and 

purchased power and transmission 

expense, not because of adding ‘‘new’’ 

Participating Projects costs. 

Comment: A comment was received 

referring to the 1983 agreement between 

Reclamation and Western that provides 

guidance for inclusion of Participating 

Projects into the PRS and believes that 

Western should follow this guidance. 

Response: Western currently abides 

by the 1983 agreement when including 

Participating Projects into the PRS by 

including only those authorized 

Participating Projects costs in the rate 

that meet the criteria. The 

apportionment methodology is then 

applied toward those projects. 

Comment: On what basis, other than 

historic practice or internal agency 

opinion, does Western justify inclusions 

of continued apportionment funds for 

non-authorized projects in the PRS? 

Response: Western adheres to the 

CRSP Act, specifically section 5, which 

requires the inclusion of the 

Participating Projects and the 

apportionment of revenues in the PRS. 

In addition, DOE Order RA 6120.2, 

specifically section 12(b)(5), states, 

‘‘expected revenues are at least 

sufficient to recover other costs such as 

payments to basin funds, Participating 

Projects or States.’’ Western’s obligation 

to collect apportionment revenues is 

independent of a state’s authorization to 

spend their apportioned revenues. 

Comment: A commenter states it is 

undisputed that the current rate will 

collect sufficient revenues to meet all 

proposed expenditures over the 5-year 

rate window. 

Response: It is true that the current 

rate will collect sufficient revenues for 

a 5-year, rate cost evaluation period. 

However, DOE Order RA 6120.2, section 

12, requires revenues to be sufficient to 

recover annual expenses and repayment 

through the ratesetting period (through 

FY 2025 in this ratesetting PRS). 

According to Reclamation Law, Western 

must establish power rates sufficient to 

recover O&M expenses, purchased 

power expenses, interest expenses, and 

repayment of power investment and 

irrigation aid. For the current 17-year 

ratesetting period, from FY 2009 

through FY 2025, the current rate is not 

sufficient to cover expenses and 

repayment through this period. The 

current rate shows deficits in some of 

these years, including the final year of 

the study; therefore, the proposed rate 

adjustment is needed. 

Comment: Many comments were 

received stating that the comment 

period closing on May 5 was before the 

end of the formal FY 2010 WPR period 

of May 21 and wanted to ensure their 

comments on the FY 2010 WPR were 

incorporated into the final Rate Order. 

Some comments suggested Western 

extend the comment period for this rate 

process another 30 days, closing on June 

4, 2008. Others recommended that the 

O&M components of this rate 

proceeding continue to be scrubbed and 

refined in consultation with the 

customers prior to finalization of this 

rate proposal. One commenter went on 

to state, ‘‘because the formal work 

program process has not yet concluded 

prior to the comment deadline * * * we 

reserve the right to comment on those 

adjustments prior to finalization of the 

rate.’’ 

Response: Western’s FY 2010 WPR 

has been finalized; however, Western is 

committed to continue to work with its 

customers to try to reduce the budgeted 

estimates. Western also believes that 

since the second step is capped, the 

second step firm power rate can be 

reduced if the budget estimates are too 

high. In addition, Western is willing to 

work with its customers on the FY 2011 

budget process which will be used to 

determine the second step of the rate 

that will be effective October 1, 2009. 

Comments: When will the FY 2010 

WPR materials be available, and when 

will a new PRS be run with updated 

data? Will this update be provided 

before the comment forum, or will it be 

after the comment forum and before the 

close of the comment period? When will 

the FY 2010 WPR be finalized? 

Response: The WPR process for the 

FY 2010 budget was held on February 

28, 2008. Western has since reviewed 

those costs to streamline them as much 

as possible. Western presented these 

updates to planned O&M costs based on 

the updated FY 2010 WPR in the second 

public information forum, which was 

held on April 10, 2008. 

Comment: Another customer 

encouraged Western to come to some 

decisions so they can incorporate the 

forecasted rates into their budget 

planning process. 

Response: Western recognizes that its 

customers have a budget planning 

process and the rate adjustment has an 

effect on its customers’ internal 

processes. Western will be forthcoming 

with the final rates as soon as the Acting 

Deputy Secretary places the rates into 

effect on an interim basis. 

2. Cost Recovery Charge 

Comment: A comment was made that 

the early portions of the Rate Brochure 

indicate the CRC would remain in effect 

for an entire FY. However, page 17 

proposes triggering criteria with a 45- 

day customer notice. 

Response: The firm power rate 

proposal includes the CRC similar to the 

existing rate except that it also includes 

a new, additional, triggering criteria 

caused by reduced releases from Glen 

Canyon Dam. This new triggering 

criteria has the same 45-day customer 

notice as the Basin Fund balance 

criteria, but could occur whenever 

Reclamation’s 24-month study indicates 

Glen Canyon water releases will be 

reduced to less than 8.23 million acrefeet in a water year. This can happen 

any time during the year. 

Comment: A comment was made 

regarding the CRC and the example 

shown on page 14 of the Rate Brochure. 

The commenter asked if the calculation 

of annual expenses includes other 

revenues as an expense offset or are they 

included in total revenue. 

Response: The CRC includes all 

revenues and expenses. No offsetting of 

revenue or expenses occurs except for 

the purpose of calculating the CRC, nonreimbursable environmental expenses 

are capped at $27 million and indexed 

for inflation. 

Comment: Several customers 

referenced a CRC ‘‘adjuster’’ or credit 

mechanism whereby when actual 

purchased power expenses do not meet 

projections, a credit would be returned 

to the firm power customers similar to 

one in place at the Southwestern Power 

Administration. ‘‘Consider if FX is less 

than projected, the differential could be 

spread over all MWh, OR if FA is greater 

than FARR, the differential could be a 

credit.’’ 

Response: The CRC already includes 

a PYA true-up from estimates to actuals. 

For Western to implement an 

adjustment similar to Southwestern 

Power Administration, purchased 


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power would have to be unbundled 

from the firm power rate. The current 

method of socializing all purchased 

power costs into the SLCA/IP firm 

electric service rate would not be 

conducive to using a purchased power 

adjustment. The CRC includes a PYA 

true-up from estimates to actuals that is 

only applicable to those customers 

actually assessed a CRC because they 

are the ones who paid the estimated 

costs of purchasing additional firming 

energy. The customers who receive a 

CRC waiver acquire their needed 

additional energy elsewhere. 

3. Stepped Rate 

Comment: What internal process(es) 

would be required in order to change 

the CRSP MC ratemaking methodology 

from the pinch point to another 

methodology? Is Western open to this 

type of discussion? 

Response: Western would be willing 

to discuss any ratemaking methodology 

that is within its constraints of law and 

policy. 

Comment: When will the decision be 

made whether or not Western will 

implement the stepped rate? 

Response: Western has decided to 

implement the stepped rate with the 

first step being effective October 1, 

2008. 

Comment: How would the stepped 

rate work? Would the rate be one certain 

percentage, and in the second year the 

rates would automatically go up? Would 

the rate be based on the most current 

PRS in that year? 

Response: The first year will be a 

composite rate of 26.80 mills/kWh, 

which is a 6 percent increase. The 

second step will be capped at 29.68 

mills/kWh for the composite rate. This 

would be the maximum amount for the 

second step. The second step rate will 

be determined by using FY 2008 actual 

data, updated estimates for purchased 

power and transmission, as well as 

other estimates that could affect the rate. 

As of now, and for analysis purposes, 

the total composite rate of 29.68 mills/ 

kWh will be effective October 1, 2009. 

Comment: The majority of customers 

requested that Western consider 

delaying the proposed SLCA/IP rate 

adjustment by at least 1 year, stating 

that because there are a number of 

uncertainties associated with the 

proposed rate that may be resolved, 

thereby eliminating or reducing the 

need for such a high rate by October 1, 

2009. These customers recommend a 

deferment of the rate until October 1, 

2009. In the event Western is unable to 

defer the rate process, they recommend 

the implementation of a stepped rate 

with the first step October 1, 2008, of 

zero percent and the second step 

October 1, 2009, not to exceed 18 

percent. 

Response: Western believes that 

implementation of a zero-percent 

increase in the first year is the same as 

a 1-year deferment of the rate 

adjustment and is not fiscally 

responsible. Western is implementing a 

stepped rate with the first step being 

26.80 mills/kWh, which is a 6 percent 

increase. The second step will not 

exceed the cap of 29.68 mills/kWh for 

an overall 17.4 percent increase from 

the current 25.28 mills/kWh rate. 

Western believes that this will allow 

sufficient time to adjust projections 

based on the current uncertainties and 

possibly a second step increase that is 

less than current projections. 

The second step will use the FY 2008 

Final PRS, the FY 2011 WPR with the 

same 5-year cost evaluation period 

(2008–2012), the April 2009, 24-month 

study from Reclamation, and the most 

current data available for all other 

projections. 

4. Basin Fund 

Comment: Please provide an 

accounting of revenues and expenses 

which would explain the Basin Fund 

climbing from $40 million at the end of 

FY 2005 to $80 million at the end of the 

current operating year. 

Response: There are many variables 

that affect the Basin Fund balance 

increase; however, the main reason for 

the increase is the almost $116 million 

collected from power revenues for 

interest expense and principal payments 

during the years FY 2006 through FY 

2008. The main offset to these 

collections is non-reimbursable 

environmental expenses. 

In addition, Western has not been able 

to return funds to Treasury since FY 

1999 because of the continued drought. 

If the Basin Fund continues to be as 

healthy as it is today, Western is 

planning to return funds to Treasury 

this FY to satisfy the return of interest 

and principal obligations, as required 

under the CRSP Act. 

Comment: Several comments on the 

projected ‘‘healthy’’ ending balance of 

the Basin Fund suggest the rate process 

is not necessary. A commenter cited that 

Western has announced if the ending 

FY 2008 Basin Fund balance is at the 

current projected level, Western will 

probably make a transfer of funds to 

Treasury. They further stated that 

‘‘under these circumstances, holding the 

rate steady while adjusting for 

significantly increased hydrology and a 

change in law is perfectly appropriate 

and the sound course of action’’. 

Response: Western reiterates the fact 

that the balance in the Basin Fund does 

not determine the need for a rate 

process. In accordance with DOE Order 

RA 6120.2, if revenues are not sufficient 

to cover expenses and repayment 

obligations as determined by the PRS, 

the current rate is inadequate and must 

be adjusted. 

Comment: One commenter stated 

concern that ‘‘the fund itself may 

evaporate, for which Western has 

identified no contingencies. Such 

revenue losses would have tremendous 

repercussions on funding for those 

environmental programs to reduce 

salinity and remove jeopardy for 

endangered fish.’’ 

Response: Environmental program 

expenses are non-reimbursable by the 

power customers and are not included 

in the PRS for ratemaking purposes. 

However, the programs are funded out 

of the Basin Fund, and the costs are 

credited as funds returned to Treasury 

for repayment of CRSP obligations. 

5. Revenue 

Comment: A commenter asked 

Western to explain the assumed 

reduction in transmission revenue given 

the strategic planning process to 

improve transmission marketing 

services and if the transmission 

revenues used in this PRS factor in the 

new increased transmission rate. 

Response: Firm transmission revenue 

estimates in the PRS are based on firm 

contracts and rates currently in place. 

Non-firm transmission revenue 

estimates are based on a 5-year average 

of historical data. Western has no way 

to estimate increased revenues that may 

occur due to efforts to improve 

transmission marketing services. 

Comment: One commenter requested 

the first part of 2008 be included in the 

historical averages. 

Response: Western only used actuals 

from FY 2003 through FY 2007. Western 

will include FY 2004 through FY 2008, 

when determining the second step of 

the firm power rate that will be effective 

October 1, 2009. 

6. Western Expenses 

Comment: One commenter 

questioned, ‘‘Given Western’s work on 

operational consolidation, what are the 

implications for this rate process, and 

specifically, what impacts will there be 

on RMR’s work on the new billing 

system?’’ 

Responses: The increase in power 

billing is related to RMR information 

technology (IT) staff that will be 

supporting the new power billing 

system. Over the last 3 to 4 years, the 

Sierra Nevada Region maintained the 


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old system with minimal enhancements 

for RMR. As a result, the IT support 

costs have been very negligible. While 

the billing system is being developed, 

the costs will be capitalized. After that 

time, additional support will be 

expected the first year or so to get the 

system running smoothly and to 

document processes. As for cost 

allocation of the new power billing 

system, additional information will be 

provided next year. RMR and the CRSP 

MC will work with their customers on 

the allocation methodology based on the 

design of the new system and various 

other factors. 

Comment: One customer wanted to 

know if the ‘‘50–5–5’’ expenses drop 

back to a lower level after FY 2010. 

Response: The 50–5–5 initiative (50 

‘‘over-hires,’’ over 5 years, at an 

approximate cost of $5 million) is a 

recent Western-wide program designed 

to hire new staff into trainee positions 

as part of Western’s succession 

planning. The funding for these 

additional over-hire positions has been 

placed in Western’s FY 2010 budget 

submissions. The intent of this program 

is that for each trainee hired, there is a 

target retirement position. Once these 

retirements occur, the trainees will fill 

these positions and staffing levels will 

become flat again in FY 2013 and 

beyond. 

7. Reclamation Expenses and Related 

Issues 

Comment: A commenter wanted to 

know if the amounts included in the 

ratesetting PRS take into account the 

new legislation with a cap on security 

costs. In addition, they wanted to know 

how the future years’ projected amounts 

were derived, and what basis was used 

for the 94.7 percent share to power. 

They suggest the rate process should be 

deferred until the impacts of the 

security cost cap are known. 

Response: At this time, these amounts 

do not factor in the Consolidated 

Natural Resources Act of 2008, which 

includes the limitation of costs to 

customers of security activities at 

Reclamation dams. Currently, the future 

year projected amount is based on 

amounts through the FY 2010 WPR. 

Western has not received updated 

security expenses from Reclamation that 

reflect impacts of the Consolidated 

Natural Resources Act of 2008. Western 

plans to continue to work with 

Reclamation, and these expenses are 

expected to be updated and applied in 

the second step of this rate adjustment. 

The 94.7 percent share to power is 

based on an average of allocation factors 

used for the CRSP units. 

Comment: What is the status of the 

Glen Canyon cost allocation study? 

Response: Reclamation has tasked 

Argonne National Laboratory to study 

the cost allocation revisions on the Glen 

Canyon reallocation. Reclamation will 

be reviewing this work in the near 

future. 

Comment: What is the status of 

Reclamation’s analysis of project 

purpose cost allocations? 

Response: There have been several 

projects in the region that have had final 

cost allocation changes to previous 

interim allocations. For example, the 

San Juan-Chama Project March 2001 

Final Cost Allocation incorporated 

numerous project purpose changes that 

occurred since earlier Definite Plan 

Reports (DPR), such as the increase in 

the M&I purpose and inclusion of the 

purpose of the Jicarilla Apache 

Settlement. Additionally, both the 

Dolores Project December 2000 and the 

Dallas Creek Project February 2004 

Final Cost Allocations also incorporated 

some cost allocation changes as a result 

of slight purpose shifts since their last 

DPR interim allocations. Also, the 

Bonneville Unit of the Central Utah 

Project, still in construction phase, has 

had recent cost allocation changes to 

conform to its reconfiguration pursuant 

to the Reclamation Projects 

Authorization and Adjustment Act of 

1992 (Pub. L. No. 102–575). It is 

possible that the current October 2004 

Interim Cost Allocation of the 

Bonneville Unit may change again until 

there is a final cost allocation. Once a 

final cost allocation has been approved, 

any cost allocation change succeeding 

that document may need Congressional 

approval under Section 302 of the 

Department of Energy Organization Act 

(42 U.S.C. 7152). 

Comment: A commenter stated and 

asked the following: ‘‘The April 18, 

2008 response to our February 11, 2008, 

letter includes discussion regarding a 

footnote contained in Tab 19 of the 

Supporting Documentation material. It 

refers to irrigation investment costs. 

What does footnote 1 (Legal waiver of 

assistance of irrigation investigation 

costs still not available) mean? Are these 

costs related to the ALP study costs? 

The Congress directed on December 15, 

2000, that ‘Federal law does not provide 

a basis for allocating costs related to 

ALP irrigation components to the M&I 

water uses or to CRSP power customers. 

Allocating such costs would require an 

explicit change to Federal law. As the 

July 2000 EIS recognizes, in the absence 

of such a change in the law, those ‘sunk 

costs’ that are attributed to project 

features that are not part of the 

Department’s Preferred Alternative are 

non-reimbursable.’ (S. Report, 106th 

Congress, 106–513) [sic].’’ 

Response: Public Law 106–554, dated 

December 21, 2000, states, ‘‘Such 

repayment shall be consistent with 

Federal Reclamation Law, including the 

Colorado River Storage Project Act of 

1956 (43 U.S.C. 620 et seq.). Such 

agreement shall take into account the 

fact that the construction of certain 

project facilities, including those 

facilities required to provide irrigation 

water supplies from the Animas La Plata 

Project, is not authorized under 

paragraph (1)(A)(i) and no cost 

associated with the design or 

development of such facilities, 

including costs associated with 

environmental compliance, shall be 

allocable to the municipal and 

industrial users of the facilities 

authorized under such paragraph.’’ 

Reclamation believes it is clear from 

Public Law 106–554 that, although 

Reclamation is no longer authorized to 

construct irrigation facilities for the 

ALP, the costs of the design and 

development of these facilities are not 

specifically declared non-reimbursable. 

Public Law 106–554 provides only that 

those irrigation investigation costs 

cannot be allocated to the M&I users; 

otherwise, repayment shall be 

consistent with Federal Reclamation 

law, including the CRSP Act. 

Comment: An interested party asked, 

‘‘What is the basis for the cost of living 

adjustment included for Reclamation? Is 

this authorized across all Federal 

positions, across all Department of 

Interior positions, throughout 

Reclamation?’’ 

Response: The program analysts for 

the Office of Personnel Management 

determine the cost of living adjustments 

for most Federal employees. You may 

wish to visit its Web site at http:// 

www.opm.gov. Typically for budget 

purposes, Western and Reclamation 

assume a 3 percent increase based on 

historical averages. 

8. Project Use 

Comment: One commenter asked 

what causes the large increase in Project 

Use in FY 2021. 

Response: Increased requirements of 

the Navajo Indian Irrigation Project. 

Comment: One commenter asked 

where Project Use revenues appear on 

Table 3 of the Supporting 

Documentation Booklet. 

Response: The Project Use sales are 

included along with the Energy and 

Capacity sales on Table 3 of the 

Supporting Documentation Booklet and, 

therefore, are included in determining 

the energy and capacity rates. 


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9. Environmental 

Comment: A commenter asked if 

Reclamation and Western are seeking 

appropriations for the Upper Colorado 

Endangered Fish Recovery Program as 

obligated in Pub. L. 102–395. 

Response: The Recovery 

Implementation Program Act, Public 

Law 106–392, Section 3(d)(3)(2), 

provides that: ‘‘If [Western] and 

[Reclamation] determine that the funds 

in the [Basin Fund] will not be 

sufficient to meet the obligations of 

section 5(c)(1) of the [CRSP] Act for a 3- 

year period, [Western] and 

[Reclamation] shall request 

appropriations to meet base funding 

obligations.’’ Since the Basin Fund 

currently has an adequate balance for 

anticipated non-reimbursable funding 

requirements, no appropriations are 

currently being sought for the Upper 

Colorado Endangered Fish Recovery 

Program. 

Comment: A customer stated that the 

Recovery Implementation Program (RIP) 

Base Funding should be at zero after FY 

2013 until specific legislation extending 

the obligation has been passed. 

Response: Similar to the way 

Reclamation has treated security costs 

in previous WPRs, it shows potential 

RIP costs in an effort to show any costs 

that may affect the Basin Fund. Since 

RIP Base Funding is a non-reimbursable 

expense, it does not impact the firm 

power rate. 

Comment: A commenter asked if the 

Aspinall EIS is expected to be done this 

FY 2008, and if so, shouldn’t FY 2009 

and FY 2010 expenses be zero? 

Response: The current schedule for 

the Aspinall EIS shows an optimistic 

anticipated completion date of 

December 2008 (FY 2009). However, 

due to various factors and uncertainties 

in the process, Reclamation 

recommends leaving the funding in the 

budget until the EIS has been finalized. 

Comment: Two comments were 

received questioning the determination 

not to require an Environmental 

Assessment (EA) or EIS for this rate 

adjustment. 

Response: Western believes it is 

categorically excluded from an EA or 

EIS because this process is for a rate 

adjustment. There are no proposed 

changes in operations. 

Comment: One commenter suggests 

that the contracts for hydropower 

anticipate changes in flows from Glen 

Canyon Dam needed to meet the Grand 

Canyon Protection Act and the 

Endangered Species Act so that 

acquisition of replacement power 

during these flows is minimized or 

eliminated. 

Response: This rate adjustment does 

not alter Western’s contractual 

obligations. Western relies upon the 

hydropower generation estimates 

projected by the generating agency 

when planning for replacement power 

requirements. Western’s firm power 

contracts with its customers provide for 

the delivery of SHP which is the 

minimum quantity of firm energy that 

must be supplied under the contracts. 

Western’s firm power contracts do not 

expire until September 30, 2024. 

10. Hydrology 

Comment: A commenter asked what 

the actual operational expenses have 

been over the past 5 years for purchased 

power expenses for operational 

purposes, and what hydrology was used 

post-2014. 

Response: Western does not 

specifically track operational purchased 

power expenses; however, Western has 

increased this projection for several 

reasons: (a) Increased energy prices 

especially during real time on-peak 

conditions, (b) increased requests for 

special power plant operations, (c) 

increased special operations for fish 

studies, (d) increased unscheduled flow 

reduction activities, and (e) spinning 

units for voltage support. 

The hydrology study titled, ‘‘Colorado 

River Interim Guidelines for Lower 

Basin Shortages and Coordinated 

Operation for Lake Powell and Lake 

Mead’’ was used for determining the 

purchased power estimates for the years 

FY 2010 through FY 2013. Western used 

the median level of releases from the 

dams in these estimates after FY 2014. 

Comment: A commenter asked what 

month’s 24-month study is utilized in 

Table 3 of the Rate Brochure and when 

an updated study will be available with 

revised hydrology. 

Response: The April 2008, 24-month 

study will be used for the ratesetting 

Power Repayment Study (PRS) to 

project purchased power estimates for 

FY 2008 and FY 2009. In previous rate 

analyses, Western has used 

Reclamation’s long-term hydrological 

study through FY 2060. In this process, 

for long-term projections, we used the 

same method as in the last rate process 

where Western looked at the first 5 

future years then dropped purchased 

power projections down to the 

operation cost. This effectively makes 

the difference between Reclamation’s 

long-term study and the most current 

24-month study negligible. 

Comment: Several commenters asked 

if the turbine efficiency improvements 

at Glen Canyon had been factored into 

the energy calculations in this PRS. 

They suggested deferring the rate 

process until the impacts of the 

enhanced unit efficiencies are evaluated 

and included in the PRS. 

Response: Improvements in turbine 

efficiency have not been factored into 

the energy calculation for use in the 

ratesetting PRS. Western is currently 

working with Reclamation to determine 

the energy output of the turbine 

efficiency improvements at Glen 

Canyon, Flaming Gorge, and Upper and 

Lower Molina dams. If the turbine 

efficiency improvement studies are 

completed in time for input into the 

second step of the firm power rate, 

Western will factor them into the rate. 

Comment: A commenter cited 

independent studies that concluded 

climate changes could cause Lake 

Powell to go empty or at least below 

hydropower generation by 2021. The 

commenter suggests Western 

incorporate these studies into its 

hydrogeneration forecasting. 

Response: Western uses forecasts 

based on hydrological projections that 

are received from Reclamation. These 

hydrological studies look at the possible 

consequences of long term changes to 

climate. Appendix W, Climate 

Technical Work Group Report, of the 

Colorado River Interim Guidelines for 

Lower Basin Shortages and Coordinated 

Operations for Lake Powell and Lake 

Mead’s final EIS is a recent example. 

Moreover, Western’s PRSs are 

performed on a yearly basis with 

updated hydrological projections. 

Any long-term shifts in hydrology that 

would reduce hydropower generation 

will be incorporated into future data 

provided by Reclamation and will be 

reflected in Western’s PRSs at that time. 

Additionally, depletions to the runoff 

caused by future development of Upper 

Basin water allocations are included in 

Reclamation’s hydrological projections 

and are thus incorporated into 

Western’s rate determination process. 

Comment: A commenter suggested the 

rate process should be deferred until the 

uncertainties of the improved 

hydrological conditions, including 

equalization flows are evaluated and 

included in the PRS. The commenter 

questioned if there is a mechanism in 

place that will compensate for 

drastically improved hydrology. 

Response: If hydrology improves 

drastically there will be less purchased 

power costs built into the second step 

rate, FY 2009 and beyond. In addition, 

Western will use the updated generation 

forecasts when it determines the second 

step. 

11. Transmission and Ancillary Services 

Comment: A commenter wanted to 

know if a customer has to be physically 


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connected to Western’s system in order 

to receive ancillary services such as 

reactive supply, etc. 

Response: There is no predetermined 

requirement for a customer to receive 

ancillary services on Western’s 

transmission system. The criteria 

needed to determine whether or not a 

customer can receive ancillary services 

on Western’s transmission system 

include: (a) Physical interconnection, 

(b) balancing authority location, (c) type 

of customer, and (d) type of ancillary 

service required. Each request for 

ancillary services needs to be evaluated 

based on its own circumstances. 

Depending upon the responses to the 

items listed above, the providing of 

ancillary services may be mandatory or 

optional. 

Comment: A commenter asked if there 

were on/off-peak and seasonal non-firm 

rates on transmission. 

Response: CRSP MC does offer firm 

transmission on a short-term basis, 

which is usually at a non-firm rate but 

can be discounted through the OASIS 

posting process. 

Comment: A customer wanted to 

know if Contract No. 98-SLC–0390 

between Western and Utah Associated 

Municipal Power Systems (UAMPS) had 

been extended, since it terminates 

December 2008. 

Response: As of this publication date, 

this contract with UAMPS has not been 

extended. 

12. Miscellaneous 

Comment: A commenter wanted to 

know what the anticipated impacts on 

merchant function revenues were given 

the proposed merchant function 

consolidation. 

Response: Western performed a highlevel evaluation of the merchant 

functions and decided it will not be 

pursuing merchant consolidation as part 

of this strategic planning process. 

Comments: A commenter wanted to 

know what will be Western’s treatment 

regarding post-2010 SHP allocations. 

Response: Western is assuming that 

SHP allocations will remain constant 

through FY 2013 and includes firming 

purchases accordingly to meet its 

commitments. After FY 2013, Western 

continues to assume the same SHP 

allocations through the remainder of the 

PRS, but reduces the purchased power 

estimates to include only those needed 

for operations ($4 million per year). 

Comment: A commenter states it is 

unfortunate that Glen Canyon Dam was 

authorized. 

Response: This comment is outside 

the scope of this rate process. 

Comment: A comment was received 

stating that since the outcome of the 

integration of the CRSP cost allocations 

between RMR and DSW for the 

operational consolidation is unknown, 

any rate process should be deferred 

until October 1, 2009. 

Response: Western has chosen to 

proceed with Operations Consolidation 

(‘‘Option C’’ of the April 24 

presentation). Western will work with 

all customers to ensure that each project 

will be allocated its appropriate share of 

costs. Western expects to provide its 

proposed cost allocation methodologies 

to interested customers by September 1, 

2008, for their review and input. 

Availability of Information 

Information about this rate 

adjustment, including PRSs, comments, 

letters, memorandums, and other 

supporting material made or kept by 

Western and used to develop the 

provisional rates, is available for public 

review at the Colorado River Storage 

Project Management Center, Western 

Area Power Administration, 150 East 

Social Hall Avenue, Suite 300, Salt Lake 

City, Utah or at http://www.wapa.gov/ 

crsp/ratescrsp. 

Ratemaking Procedure Requirements 

Environmental Compliance 

In compliance with the National 

Environmental Policy Act (NEPA) of 

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

on Environmental Quality Regulations 

(40 CFR parts 1500–1508); and DOE 

NEPA Regulations (10 CFR part 1021), 

Western has determined that this action 

is categorically excluded from preparing 

an environmental assessment or an 

environmental impact statement. 

Determination Under Executive Order 

12866 

Western has an exemption from 

centralized regulatory review under 

Executive Order 12866; accordingly, no 

clearance of this notice by the Office of 

Management and Budget is required. 

Submission to the Federal Energy 

Regulatory Commission 

The interim rates herein confirmed, 

approved, and placed into effect, 

together with supporting documents, 

will be submitted to the Commission for 

confirmation and final approval. 

Order 

In view of the foregoing and under the 

authority delegated to me, I confirm and 

approve on an interim basis, effective 

October 1, 2008, Rate Schedule SLIP– 

F9, SP–PTP7, SP–NW3, SP–NFT6, SP– 

SD3, SP–RS3, SP–EI3, SP–FR3, and SP– 

SSR3 for the Salt Lake City Area 

Integrated Projects 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 

September 30, 2013. 

Dated: September 4, 2008. 

Jeffrey F. Kupfer, 

Acting Deputy Secretary. 

Rate Schedule SLIP–F9 

(Supersedes Schedule SLIP–F8) 

United States Department of Energy 

Western Area Power Administration 

Salt Lake City Area Integrated Projects; 

Arizona, Colorado, Nevada, New Mexico, 

Utah, Wyoming 

Schedule of Rates for Firm Power 

Service 

Effective: The first step of the stepped 

rate will be effective on the first day of 

the first full billing period beginning on 

or after October 1, 2008; the second step 

will be effective on the first day of the 

first full billing period on or after 

October 1, 2009, extending through 

September 30, 2013, or until superseded 

by another rate schedule, whichever 

occurs earlier. 

Available: In the area served by the 

Salt Lake City Area Integrated Projects. 

Applicable: To the wholesale power 

customer for firm power service 

supplied through one meter at one point 

of delivery, or as otherwise established 

by contract. 

Character: Alternating current, 60 

hertz, three-phase, delivered and 

metered at the voltages and points 

established by contract. 

Monthly Rate: First step, effective 

October 1, 2008: 

DEMAND CHARGE: $4.70/kilowatt of 

billing demand. 

ENERGY CHARGE: 11.06 mills/ 

kilowatthour of use. 

Second step, effective October 1, 

2009, and not to exceed the following: 

DEMAND CHARGE: $5.22/kilowatt of 

billing demand. 

ENERGY CHARGE: 12.29 mills/ 

kilowatthour of use. 

COST RECOVERY CHARGE: This 

charge will be recalculated annually 

before May 1, and Western will provide 

notification to the customers. The 

charge, if needed, will be placed into 

effect from October 1 through 

September 30. If triggered by the 

Shortage Criteria, the CRC will be recalculated at that time and may be 

implemented at any time of the year 

upon 45-day notice to customers. (See 

Shortage Criteria Trigger explanation 

below.) The CRC will be calculated as 

follows: 


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CRC CALCULATION

Description Formula 

STEP ONE: Determine the Net Balance available in the Basin Fund 

BFBB: Basin Fund Beginning Balance ($) ............................................................................. Financial forecast. 

BFTB: Basin Fund Target Balance ($) .................................................................................. .15 * PAE (not less than $20 million). 

PAR: Projected Annual Revenue ($) w/o CRC ..................................................................... Financial forecast. 

PAE: Projected Annual Expense ($) ...................................................................................... Financial forecast. 

NR: Net Revenue ($) ............................................................................................................. PAR¥PAE. 

NB: Net Balance ($) ............................................................................................................... BFBB + NR. 

STEP TWO: Determine the Forecasted Energy Purchased Expenses 

EA: SHP Energy Allocation (GWh) ........................................................................................ Customer contracts. 

HE: Forecasted Hydro Energy (GWh) ................................................................................... Hydrologic & generation forecast. 

FE: Forecasted Energy Purchased (GWh) ............................................................................ EA¥HE. 

FFC: Forecasted Avg Energy Price per MWh ($) ................................................................. From commercially available price indices. 

FX: Forecasted Energy Purchased Expense ($) ................................................................... FE * FFC. 

STEP THREE: Determine the amount of Funds Available for firming energy purchases, and then determine additional revenue to be 

recovered. The following two formulas will be used to determine FA, the lesser of the two will be used 

FA1: Basin Fund Balance Factor ($) ..................................................................................... If (NB > BFBB, FX, FX¥(BFTB¥NB)). 

FA2: Revenue Factor ($) ....................................................................................................... If (NR >¥.25 * BFBB, FX, FX + NR + .25 * BFBB). 

FA: Funds Available ($) ......................................................................................................... Lesser of FA1 or FA2 (not less than $0). 

FARR: Additional Revenue to be Recovered ($) ................................................................... FX¥FA. 

STEP FOUR: Once the FA for purchases has been determined, the CRC can be calculated, and the WL can be determined 

WL: Waiver Level (GWh) ....................................................................................................... If (EA < HE, EA, HE + (FE * (FA/FX))), but not less 

than HE. 

WLP: Waiver Level Percentage of Full SHP ......................................................................... WL/EA * 100. 

CRCE: CRC Energy (GWh) ................................................................................................... EA¥WL. 

CRCEP: CRC Energy Percentage of Full SHP ..................................................................... CRCE/EA * 100. 

CRC: Cost Recovery Charge (mills/kWh) .............................................................................. FARR/(EA * 1,000). 

Narrative CRC Example 

Step One: Determine the net balance 

available in the Basin Fund. 

BFBB—Western will forecast the 

Basin Fund Beginning Balance for the 

next FY. 

BFTB—Determine the Basin Fund 

Target Balance for the next FY. The 

BFTB will not be less than $20 million. 

The target is 15 percent of projected 

annual expenses for the coming FY. 

BFTB = 0.15*PAE. 

PAR—Projected Annual Revenue is 

Western’s estimate of revenue for the 

next FY. 

PAE—Projected Annual Expenses is 

Western’s estimate of expenses for the 

next FY. The PAE includes all expenses 

plus non-reimbursable expenses, which 

are capped at $27 million per year plus 

an inflation factor. This limitation is for 

CRC formula calculation purposes only, 

and is not a cap on actual nonreimbursable expenses. 

NR—Net Revenue equals revenues 

minus expenses. NR = PAR¥PAW. 

NB—Net Balance is the Basin Fund 

Beginning Balance plus net revenue. NB 

= BFBB+NR. 

Step Two: Determine the forecasted 

energy purchased expenses. 

EA—The Sustainable Hydropower 

Energy Allocation. This does not 

include Project Use customers. 

HE—Western’s forecast of Hydro 

Energy available during the next FY 

developed from Reclamation’s April, 24- 

month, study. 

FE—Forecasted Energy purchases are 

the difference between the sustainable 

hydropower allocation and the 

forecasted hydro energy available for the 

next FY, or the anticipated firming 

purchases for the next year. FE = 

EA¥HE. 

FFC—The forecasted energy price for 

the next FY per MWh. 

FX—Forecasted energy purchased 

power expenses based on the current 

year April 24-month study, representing 

an estimate of the total costs of firming 

purchases for the coming FY. FX = 

FE*FFC. 

Step Three: Determine the amount of 

Funds Available (FA) to expend on 

firming energy purchases, and then 

determine additional revenue to be 

recovered (FARR). The following two 

formulas will be used to determine FA; 

the lesser of the two will be used. Funds 

available shall not be less than zero. 

A. Basin Fund Balance Factor (FA1) 

The first factor ensures that the Net 

Balance will not go below 15 percent of 

the total expenses for that FY. If the Net 

Balance is greater than the Basin Fund 

Target Balance, then use the value for 

forecasted energy purchased power 

expenses. If the net balance is less than 

the Basin Fund Target Balance, then 

reduce the value of the Forecasted 

Energy Purchased Power Expenses by 

the difference between the Basin Fund 

Target Balance and the Net Balance. 

FA1 = if (NB>BFTB, FX, 

FX¥(BFTB¥NB)) 

If the Net Balance is greater than the 

Basin Fund Target Balance, then FA1 = 

FX. 

If the Net Balance is less than the 

Basin Fund Target Balance, then FA1 = 

FX¥(BFTB¥NB). 

B. Basin Fund Revenue Factor (FA2) 

The second factor ensures that the net 

revenue does not result in a loss that 

exceeds 25 percent of the Basin Fund 

Beginning Balance. If the Net Revenue 

is greater than a minus 25 percent of the 

Basin Fund Beginning Balance, then use 

the value for forecasted energy 

purchased power expenses. If the Net 

Revenue is less than a minus 25 percent 

of the Basin Fund Beginning Balance, 

then add the Net Revenue; and 25 

percent of the Basin Fund Beginning 


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Balance to the forecasted energy 

purchased power expenses. 

FA2 = If (NR>¥0.25*BFBB, FX, FX + 

NR + 0.25*BFBB) 

If the Net Revenue does not result in 

a loss that exceeds 25 percent of the 

Basin Fund Beginning Balance, then 

FA2 = FX. 

If the Net Revenue results in a loss 

that exceeds 25 percent of the Basin 

Fund Beginning Balance, then FA2 + FX 

+ NR + 0.25*BFBB. 

FA—Determine the funds available 

for purchasing firming energy by using 

the lesser of FA1 and FA2. 

FARR—Calculate the additional 

revenue to be recovered by subtracting 

the Funds Available from the forecasted 

energy purchased power expenses. 

FARR = FX¥FA. 

Step Four: Once the funds available 

for purchases have been determined, the 

CRC can be calculated and the Waiver 

Level (WL) can be determined. 

A. Cost Recovery Charge: The CRC 

will be a charge to recover the 

additional revenue required as 

calculated in Step 3. The CRC will 

apply to all customers who choose not 

to request a waiver of the CRC, as 

discussed below. The CRC equals the 

additional revenue to be recovered 

divided by the total energy allocation to 

all customers for the FY. 

CRC = FARR/(EA*1,000) 

B. Waiver Level: 

Western established an energy WL 

that provides customers the ability to 

reduce their purchased power expenses 

by scheduling less energy than their 

contractual amounts. Therefore, 

Western will establish an energy WL. 

For those customers who voluntarily 

schedule no more energy than their 

proportionate share of the WL, Western 

will waive the CRC for that year. 

After the Funds Available have been 

determined, the WL will be set at the 

sum of the energy that can be provided 

through hydro generation and 

purchased with Funds Available. The 

WL will not be less than the forecasted 

Hydro Energy. 

WL = If (EA<HE, EA, HE + (FA/FX)) 

If SHP Energy Allocation is less than 

forecasted Hydro Energy available, then 

WL = EA. 

If SHP Energy Allocation is greater 

than forecasted Hydro Energy available, 

then WL = HE + (FE*(FA/FX)). 

Prior Year Adjustment: The CRC PYA 

for subsequent years will be determined 

by comparing the prior year’s estimated 

firming-energy cost to the prior year’s 

actual firming-energy cost for the energy 

provided above the WL. The PYA will 

result in an increase or decrease to a 

customer’s firm energy costs over the 

course of the following year. The 

following table is the calculation of a 

PYA. 

PYA CALCULATION

Description Formula 

STEP ONE: Determine actual expenses and purchases for previous year’s firming. This data will be obtained from Western’s financial 

statements at the end of the FY 

PFX: Prior Year Actual Firming Expenses ($) ................................................................................................................. Financial Statements. 

PFE: Prior Year Actual Firming Energy (GWh) ............................................................................................................... Financial Statements. 

STEP TWO: Determine the actual firming cost for the CRC portion 

EAC: Sum of the energy allocations of customers subject to the PYA (GWh).

FFC: Forecasted Firming Energy Cost ($/MWh) ............................................................................................................. From CRC Calculation. 

AFC: Actual Firming Energy Cost ($/MWh) ..................................................................................................................... PFX/PFE. 

CRCEP: CRC Energy Percentage ................................................................................................................................... From CRC Calculation. 

CRCE: Purchased Energy for the CRC (GWh) ............................................................................................................... EAC*CRCEP. 

STEP THREE: Determine Revenue Adjustment (RA) and PYA 

RA: Revenue Adjustment ($) ........................................................................................................................................... (AFC¥FFC)*CRCE*1,000. 

PYA: Prior Year Adjustment (mills/kWh) .......................................................................................................................... (RA/EAC)/1,000. 

Narrative PYA Calculation 

Step One: Determine actual expenses 

and purchases for previous year’s 

firming. This data will be obtained from 

Western’s financial statements at the 

end of the FY. 

PFX—Prior year actual firming 

expense. 

PFE—Prior year actual firming energy. 

Step Two: Determine the actual 

firming cost for the CRC portion. 

EAC—Sum of the energy allocations 

of customers subject to the PYA. 

CRCE—The amount of CRC Energy 

needed. 

AFC—The Actual Firming Energy 

Cost is the PFX divided by the PFE. 

AFC = (PFX/PFE)/1,000 

Step Three: Determine Revenue 

Adjustment (RA) and Prior Year 

Adjustment (PYA). 

RA—The Revenue Adjustment is AFC 

less FFC times CRCE. 

RA = (AFC¥FFC)*CRCE)*1,000 

PYA—The PYA is the RA divided by 

the EAC for the CRC customers only. 

PYA = (RA/EAC)/1,000 

The customer’s PYA will be based on 

their prior year’s energy multiplied by 

the resulting mills/kWh to determine 

the dollar amount that will be assessed. 

The customers will be charged or 

credited for this dollar amount equally 

in the remaining months of the next 

year’s billing cycle. Western will 

attempt to complete this calculation by 

December of every year. Therefore, if the 

PYA is calculated in December, the 

charge/credit will be spread over the 

remaining 9 months of the FY (January 

through September). 

Shortage Criteria Trigger: In the event 

that Reclamation’s 24-month study 

projects that Glen Canyon Dam water 

releases will drop below 8.23 MAF in a 

water year (October through September), 

Western will recalculate the CRC to 

include those lower estimates of 

hydropower generation and the 

estimated costs for the additional 

purchased power necessary to meet 

contractual requirements. Western, as in 

the yearly projection for the CRC, will 

give the customers a 45-day notice to 

request a waiver of the CRC, if they do 

not want to have the CRC charge added 

to their energy bill. This recalculated 

CRC will remain in effect for the 

remainder of the current FY. 

In the event that Glen Canyon Dam 

water releases return to 8.23 MAF or 

higher level during the trigger 


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52994 Federal Register / Vol. 73, No. 178 / Friday, September 12, 2008 / Notices 

implementation, the CRC will be 

recalculated and the customer will be 

notified. 

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 more than, the delivery 

obligation under the power sales 

contract, or 

2. The Contract Rate of Delivery. 

Billing Energy: The billing energy will 

be the energy measured during the 

month up to, but not more than, the 

delivery obligation under the power 

sales contract. 

Adjustment for Waiver: Customers 

may choose to take a reduced SHP 

energy allocation as determined in the 

attached formulas for the CRC, and they 

will be billed the Energy and Capacity 

rates listed above, but not the CRC. 

Adjustment 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 in the 

contract. 

Adjustment for Power Factor: The 

customer will be required to maintain a 

power factor at all points of 

measurement between 95 percent 

lagging and 95 percent leading. 

Adjustment for Western Replacement 

Power: Pursuant to the Contractor’s 

Firm Electric Service Contract, as 

amended, Western will bill the 

Contractor for its proportionate share of 

the costs of Western Replacement Power 

(WRP) within a given time period. 

Western will include in the Contractor’s 

monthly power bill the cost of the WRP 

and the incremental administrative 

costs associated with WRP. 

Adjustment for Customer 

Displacement Power Administrative 

Charges: Western will include in the 

Contractor’s regular monthly power bill 

the incremental administrative costs 

associated with Customer Displacement 

Power. 

Rate Schedule SP–PTP7 

(Supersedes Schedule SP–PTP6) 

United States Department of Energy 

Western Area Power Administration 

Colorado River Storage Project; Arizona, 

Colorado, New Mexico, Utah 

Schedule of Rate for Firm Point-toPoint Transmission Service 

Effective: The first day of the first full 

billing period beginning on or after 

October 1, 2008, and extending through 

September 30, 2013, or until superseded 

by another rate schedule, whichever 

occurs earlier. 

Available: In the area served by the 

Colorado River Storage Project (CRSP) 

transmission system. 

Applicable: To firm point-to-point 

transmission service customers for 

which power and energy are supplied to 

the CRSP transmission system at points 

of interconnection with other systems 

and transmitted and delivered, less 

losses, to points of delivery on the CRSP 

transmission system established by 

contract. 

Character and Conditions of Service: 

Transmission service for alternating 

current, 60 hertz, three-phase, delivered 

and metered at the voltages and points 

of delivery established by contract. 

Point-to-Point Rate Formula: The firm 

point-to-point rate is based on a test 

year using an annual fixed charge 

methodology. The test year is the most 

recent historical data available. The 

annual revenue requirement is reduced 

by revenue credits. The resultant net 

annual cost to be recovered is divided 

by the capacity reservation needed to 

meet firm power and transmission 

commitments in kW, including the total 

network integration loads at system 

peak, to derive a cost/kWyear. The cost/ 

kWyear is calculated using the 

following formula: 

1. ATRR − = TRC NATRR

NATRR

TSTL

2.

Where: 

ATRR = Annual Transmission Revenue 

Requirement. The costs associated with 

facilities that support the transfer 

capability of the CRSP transmission 

system, excluding generation facilities. 

These costs include investment costs, 

interest expense, depreciation expense, 

administrative and general expenses, and 

operation and maintenance expenses, 

including transmission purchases. 

Transmission purchases reflect those 

costs associated with CRSP contractual 

rights. 

TRC = Transmission Revenue Credits. The 

revenues generated by the CRSP 

transmission system, such as scheduling 

and dispatch ancillary service revenues 

and phase shifter revenues, and 

excluding long-term firm transmission 

revenues. 

NATRR = Net Annual Transmission Revenue 

Requirement. The Annual Revenue 

Requirement less Transmission Revenue 

Credits. 

TSTL = CRSP Transmission System Total 

Load. The sum of the total CRSP 

transmission capacity under the longterm reservation plus the total network 

integration loads at system peak. 

This formula will be recalculated 

annually by applying the data from the 

most current historical test year. If 

needed, a revised rate will be placed 

into effect every October 1. Western will 

provide notification 30 days prior to a 

revised rate becoming effective. The rate 

for transmission service includes 

scheduling, system control, and 

dispatch. Rate Schedule SP–RS3, or any 

superseding rate schedule, for reactive 

supply and voltage control is attached 

as part of this Rate Schedule and applies 

to firm point-to-point transmission 

customers. 

Billing: The point-to-point 

transmission customer will be billed 

monthly by applying the resulting rate 

to the maximum amount of capacity 

reserved, payable whether used or not, 

except as otherwise provided in existing 

contracts. 

Requirements for Reactive Power: 

Requirements for reactive power shall 

be as established by contract; otherwise, 

there shall be no entitlement to transfer 

of reactive kilovolt amperes at delivery 

points except when such transfers may 

be mutually agreed upon by the 

Contractor and the contracting officer or 

their authorized representatives. 

Adjustment for Losses: Power and 

energy losses incurred in connection 

with the transmission and delivery of 

power and energy under this rate 

schedule shall be supplied by the 

customer as established by contract. If 

losses are not fully provided by a 

transmission customer, charges for 

financial compensation may apply. 

Adjustment for Industry 

Restructuring: Any transmission-related 

costs incurred by Western due to 

electric industry restructuring or other 

industry changes associated with 

providing CRSP transmission service 

will be passed through to each 

transmission customer, as appropriate. 

Rate Schedule SP–NW3 

(Supersedes Schedule SP–NW2) 

United States Department of Energy 

Western Area Power Administration 

Colorado River Storage Project; Arizona, 

Colorado, New Mexico, Utah 

Monthly Charge Calculation for 

Network Integration Transmission 

Service 

Effective: The first day of the first full 

billing period beginning on or after 

October 1, 2008, and extending through 

September 30, 2013, or until superseded 

by another rate schedule, whichever 

occurs earlier. 

Available: In the area served by the 

Colorado River Storage Project (CRSP) 

transmission system. 

Applicable: To network transmission 

service customers for which power and 

energy are supplied to the CRSP 

transmission system at points of 

interconnection with other systems and 

transmitted and delivered, less losses, to 


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points of delivery on the CRSP 

transmission system established by 

contract. 

Character and Conditions of Service: 

Transmission service for alternating 

current, 60 hertz, three-phase, delivered 

and metered at the voltages and points 

of delivery established by contract. 

Monthly Network Formula: The 

Network integration transmission 

service charge will be the product of the 

network customer’s load ratio share 

times one twelfth (1⁄12) of the total net 

annual transmission revenue 

requirement. The same Net Annual 

Transmission Revenue Requirement is 

used in determining the rate for network 

transmission service as for point-topoint transmission service. It is based 

on a test year using an annual fixed 

charge methodology. The test year is the 

most recent year for which historical 

data is available. The annual revenue 

requirement is reduced by revenue 

credits. The formula is as follows: 

1. ATRR

 Transmission customer’s Load-R

− =

×

TRC NATRR

NATRR 2

12

. atio Share

Where: 

ATRR = Annual Transmission Revenue 

Requirement. The costs associated with 

facilities that support the transfer 

capability of the CRSP transmission 

system, excluding generation facilities. 

These costs include investment costs, 

interest expense, depreciation expense, 

administrative and general expenses, and 

operation and maintenance expenses, 

including transmission purchases. 

Transmission purchases reflect those 

costs associated with CRSP contractual 

rights. 

TRC = Transmission Revenue Credits. The 

revenues generated by the CRSP 

transmission system, such as scheduling 

and dispatch ancillary services revenues 

and phase shifter revenues, and 

excluding long-term firm transmission 

revenues. 

NATRR = Net Annual Transmission Revenue 

Requirement. The Annual Revenue 

Requirement less Transmission Revenue 

Credits. 

Load-Ratio Share = Network customer’s 

hourly load (including its designated 

network load not physically 

interconnected with Western) coincident 

with Western’s monthly CRSP 

transmission system peak. 

This formula will be recalculated 

annually by applying the data from the 

most current historical test year. If 

needed, a revised rate will be placed 

into effect every October 1. Western will 

provide notification 30 days prior to a 

revised rate becoming effective. 

The monthly charge for network 

transmission service includes 

scheduling, system control, and 

dispatch. Rate Schedule SP–RS3, or any 

superseding rate schedule, will be 

attached as part of this Rate Schedule 

and applies to network transmission 

customers. 

Billing: Billing determinants for the 

formula rate above will be as specified 

in the service agreement. 

Requirements for Reactive Power: 

Requirements for reactive power shall 

be as established by contract; otherwise, 

there shall be no entitlement to transfer 

of reactive kilovolt amperes at delivery 

points except when such transfers may 

be mutually agreed upon by the 

Contractor and the contracting officer or 

their authorized representatives. 

Adjustment for Losses: Power and 

energy losses incurred in connection 

with the transmission and delivery of 

power and energy under this rate 

schedule shall be supplied by the 

customer as established by contract. If 

losses are not fully provided by a 

transmission customer, charges for 

financial compensation may apply. 

Adjustment for Industry 

Restructuring: Any transmission-related 

costs incurred by Western due to 

electric industry restructuring or other 

industry changes associated with 

providing CRSP transmission service 

will be passed through to each 

transmission customer, as appropriate. 

Rate Schedule SP–NFT6 

(Supersedes Schedule SP–NFT5) 

United States Department of Energy 

Western Area Power Administration 

Colorado River Storage Project; Arizona, 

Colorado, New Mexico, Utah 

Schedule of Rate for Non-Firm Point-toPoint Transmission Service 

Effective: The first day of the first full 

billing period beginning on or after 

October 1, 2008, and extending through 

September 30, 2013, or until superseded 

by another rate schedule, whichever 

occurs earlier. 

Available: In the area served by the 

Colorado River Storage Project (CRSP) 

transmission system. 

Applicable: To non-firm point-topoint transmission service customers for 

which power and energy are supplied to 

the CRSP transmission system at points 

of interconnection with other systems 

and transmitted and delivered, less 

losses, to points of delivery on the CRSP 

transmission system as established by 

contract. 

Character and Conditions of Service: 

Transmission service on an interruptible 

basis for three-phase alternating current 

60 hertz, delivered and metered at the 

voltages and points of delivery specified 

in the service contract or in advance by 

the Western Area Power Administration 

(Western). Conditions for curtailment 

shall be determined by Western and in 

accordance with Western’s Tariff. 

Rate: The proposed rate for non-firm, 

point-to-point, CRSP transmission 

service is based upon the firm point-topoint rate expressed in mills/kWh. This 

rate may be discounted. 

Billing: The rate will be applied to 

each kWh delivered at the point of 

delivery, as specified in the service 

contract. 

Adjustments for Reactive Power: 

None. There shall be no entitlement to 

transfer of reactive kilovolt-amperes at 

delivery points, except when such 

transfers may be mutually agreed upon 

by the Contractor and the contracting 

officer or their authorized 

representatives. 

Adjustments for Losses: Power and 

energy losses incurred in connection 

with the transmission and delivery of 

power and energy under this rate 

schedule shall be supplied by the 

customer in accordance with the service 

contract. If losses are not fully provided 

by a transmission customer, charges for 

financial compensation may apply. 

Adjustment for Industry 

Restructuring: Any transmission-related 

costs incurred by Western due to 

electric industry restructuring or other 

industry changes associated with 

providing CRSP transmission service 

will be passed through to each 

transmission customer, as appropriate. 

Rate Schedule SP–SD3 

(Supersedes Schedule SP–SD2) 

United States Department of Energy 

Western Area Power Administration 

Colorado River Storage Project; Arizona, 

Colorado, New Mexico, Utah 


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Schedule of Rate for Scheduling, 

System Control, and Dispatch Ancillary 

Services 

Effective: Beginning on October 1, 

2008, and extending through September 

30, 2013. 

Available: In the area served by the 

Colorado River Storage Project (CRSP) 

transmission system. 

Applicable: To all CRSP transmission 

customers receiving this service. 

Character of Service: Scheduling, 

System Control, and Dispatch service is 

required to schedule the movement of 

power through, out of, within, or into a 

balancing authority. 

Rate: Included in appropriate 

transmission rates. 

Rate Schedule SP–RS3 

(Supersedes Schedule SP–RS2) 

United States Department of Energy 

Western Area Power Administration 

Colorado River Storage Project; Arizona, 

Colorado, New Mexico, Utah 

Schedule of Rate for Reactive Supply 

and Voltage Control Ancillary Service 

Effective: Beginning on October 1, 

2008, and extending through September 

30, 2013. 

Available: In the area served by the 

Colorado River Storage Project (CRSP) 

Transmission system. 

Applicable: To all CRSP transmission 

customers receiving this service. 

Character of Service: Reactive power 

is support provided from generation 

facilities that is necessary to maintain 

transmission voltages within acceptable 

limits of the system. 

Rate: Provided through WALC 

balancing authority under Rate 

Schedule DSW–RS2 or WACM 

balancing authority under Rate 

Schedule L–AS2, or as superseded. 

Rate Schedule SP–EI3 

(Supersedes Schedule SP–EI2) 

United States Department of Energy 

Western Area Power Administration 

Colorado River Storage Project; Arizona, 

Colorado, New Mexico, Utah 

Schedule of Rate for Energy Imbalance 

Ancillary Service 

Effective: Beginning on October 1, 

2008, and extending through September 

30, 2013. 

Available: In the area served by the 

Colorado River Storage Project (CRSP) 

transmission system. 

Applicable: To all CRSP transmission 

customers receiving this service. 

Character of Service: Provided when 

a difference occurs between the 

schedules and the actual delivery of 

energy to a load located within a 

balancing authority over a single hour. 

Rates: Provided through WALC 

balancing authority under Rate 

Schedule DSW–EI2 or WACM balancing 

authority under Rate Schedule L–AS4, 

or as superseded, or the customer can 

make alternative comparable 

arrangements to satisfy its Energy 

Imbalance service obligations. 

Rate Schedule SP–FR3 

(Supersedes Schedule SP–FR2) 

United States Department of Energy 

Western Area Power Administration 

Colorado River Storage Project; Arizona, 

Colorado, New Mexico, Utah 

Schedule of Rate for Regulation and 

Frequency Response Ancillary Service 

Effective: Beginning on October 1, 

2008, and extending through September 

30, 2013. 

Available: In the area served by the 

Colorado River Storage Project (CRSP) 

transmission system. 

Applicable: To all CRSP transmission 

customers receiving this service. 

Character of Service: Necessary to 

provide the continuous balancing of 

resources, generation and interchange, 

with load and for maintaining schedules 

interconnection frequency at 60 cycles 

per second (60 Hz). 

Rate: If the CRSP MC has regulation 

available for sale, the SLCA/IP firm 

power capacity rate, currently in effect, 

will be charged. If regulation is 

unavailable from SLCA/IP resources, the 

WALC or WACM balancing authorities 

can provide the service, in accordance 

with their respective rate schedules. 

Rate Schedule SP–SSR3 

(Supersedes Schedule SP–SSR2) 

United States Department of Energy 

Western Area Power Administration 

Colorado River Storage Project; Arizona, 

Colorado, New Mexico, Utah 

Schedule of Rates for Spinning and 

Supplemental Reserve Ancillary 

Service 

Effective: Beginning on October 1, 

2008, and extending through September 

30, 2013. 

Available: In the area served by the 

Colorado River Storage Project (CRSP) 

transmission system. 

Applicable: To all CRSP transmission 

customers receiving this service. 

Character of Service: Spinning 

Reserve is defined in Schedule 5 of 

Western Area Power Administration’s 

Open Access Transmission Tariff. 

Supplemental Reserve is defined in 

Schedule 6 of Western Area Power 

Administration’s Open Access 

Transmission Tariff. 

Rate: If CRSP resources are available, 

the charge will be determined based on 

market rates plus administrative costs. If 

CRSP resources are not available, CRSP 

will purchase spinning reserves and 

pass through the costs associated with 

these purchases, including 

administrative costs. 

[FR Doc. E8–21176 Filed 9–11–08; 8:45 am] 

BILLING CODE 6450–01–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

[FRL–8714–3] 

Agency Information Collection 

Activities OMB Responses 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Notice. 

SUMMARY: This document announces the 

Office of Management and Budget’s 

(OMB) responses to Agency Clearance 

requests, in compliance with the 

Paperwork Reduction Act (44 U.S.C. 

3501 et seq.). An agency may not 

conduct or sponsor, and a person is not 

required to respond to, a collection of 

information unless it displays a 

currently valid OMB control number. 

The OMB control numbers for EPA’s 

regulations are listed in 40 CFR part 9 

and 48 CFR chapter 15. 

FOR FURTHER INFORMATION CONTACT: Rick 

Westlund (202) 566–1682, or e-mail at 

westlund.rick@epa.gov and please refer 

to the appropriate EPA Information 

Collection Request (ICR) Number. 

SUPPLEMENTARY INFORMATION: 

OMB Responses to Agency Clearance 

Requests 

OMB Approvals 

EPA ICR Number 1669.05; Lead-Based 

Paint Pre-Renovation Information 

Dissemination—TSCA Section 406(b); 

in 40 CFR part 735, subpart E; was 

approved 08/14/2008; OMB Number 

2070–0158; expires 08/31/2011. 

Dated: September 8, 2008. 

Sara Hisel-McCoy, 

Director, Collection Strategies Division. 

[FR Doc. E8–21314 Filed 9–11–08; 8:45 am] 

BILLING CODE 6560–50–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

[EPA–HQ–OPPT–2008–0661; FRL–8381–5] 

Certain New Chemicals; Receipt and 

Status Information 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Notice. 

SUMMARY: Section 5 of the Toxic 

Substances Control Act (TSCA) requires 

any person who intends to manufacture 


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