[Federal Register Volume 73, Number 178 (Friday, September 12, 2008)]
[Notices]
[Pages 52980-52996]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E8-21176]


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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.

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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superseded.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 <a href="/cdn-cgi/l/email-protection#ceb9afbcbcaba08eb9afbeafe0a9a1b8"><span class="__cf_email__" data-cfemail="99eef8ebebfcf7d9eef8e9f8b7fef6ef">[email protected]</span></a>, 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 
<a href="/cdn-cgi/l/email-protection#533f3c35273a3d3013243223327d343c25"><span class="__cf_email__" data-cfemail="bfd3d0d9cbd6d1dcffc8decfde91d8d0c9">[email protected]</span></a>.

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.
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    \1\ FERC 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).
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    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 
non-firm 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

[[Page 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 
watt-hours 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

[[Page 52982]]

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),

[[Page 52983]]

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
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                                                                                                     Percent
                                     Current rate October 1, 2005-  Proposed rate  October 1, 2008   increase   Proposed rate\1\  October 1,     Total
                                          September 30, 2010                   (1st step)            for 1st    2009-September 30, 2013  (2nd   percent
                                                                                                       step                 step)               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,

[[Page 52984]]

developing customer's load schedules, and making purchases.

                              CRC Schedule
------------------------------------------------------------------------
                   Task                                Date\1\
------------------------------------------------------------------------
April 24-Month Study (Forecast to Model     April 1.
 Projections).
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 
non-firm 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 fixed-charge methodology. The 
annual transmission revenue requirement is reduced by revenue credits 
such as non-firm 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:
    [GRAPHIC] [TIFF OMITTED] TN12SE08.000
    
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 point-to-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 point-to-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,

[[Page 52985]]

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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                             Provisional rate\1\
                                      Current rate  October     Provisional rate     Percent increase  for     October 1, 2009-        Total percent
                                       1, 2005-  September    October 1, 2008  (1st         1st step          September 30, 2013          increase
                                            30, 2010                  step)                                       (2nd step)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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    To be determined for   To be determined for   To be determined for
                                                              FY 09.                  FY 09.                 FY 10.                 FY 10.
Network Transmission (net annual     $72,613,170 (FY 08)...  To be determined for    To be determined for   To be determined for   To be determined for
 revenue requirement).                                        FY 09.                  FY 09.                 FY 10.                 FY 10.
Non-firm Transmission Rate.........  3.03 mills/kWh, may be  To be determined for    To be determined for   To be determined for   To be determined for
                                      discounted (FY 08).     FY 09.                  FY 09.                 FY 10.                 FY 10.
Ancillary Services \2\.............  N/A...................  N/A...................  N/A..................  N/A..................  N/A.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Maximum rate for FY 2010-2013.
\2\ Since 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]
------------------------------------------------------------------------
                                                 Proposed
                                    Existing    rate with    Difference
                                      rate         cap
------------------------------------------------------------------------
Total revenues..................      828,785      919,125       90,340
 
      Revenue Distribution
Expenses:
    O&M.........................      314,501      348,731       34,230
    Purchased Power and                76,489      133,525       57,036
     Transmission...............
    Integrated Projects                38,820       37,733       (1,087)
     Requirements...............
    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                    0            0            0
     (deficits).................
    Original Project and              198,009       96,812     (101,197)
     Additions..................
    Replacements................      137,183      206,803       69,620
    Irrigation..................       12,829       13,186          357
    Irrigation to Participating             0            0            0
     Projects...................
                                 ---------------------------------------
        Total Principal Payments      348,021      316,801      (31,220)
                                 ---------------------------------------

[[Page 52986]]

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

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;

[[Page 52987]]

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 acre-feet 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, non-reimbursable 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

[[Page 52988]]

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

[[Page 52989]]

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.

[[Page 52990]]

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

[[Page 52991]]

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 high-level 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 re-calculated 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:

[[Page 52992]]



                                                 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    Financial forecast.
 CRC.
PAE: Projected Annual Expense ($)......  Financial forecast.
NR: Net Revenue ($)....................  PAR-PAE.
NB: Net Balance ($)....................  BFBB + NR.
----------------------------------------------------------------------------------------------------------------
STEP TWO: Determine the Forecasted Energy Purchased Expenses
----------------------------------------------------------------------------------------------------------------
EA: SHP Energy Allocation (GWh)........  Customer contracts.
HE: Forecasted Hydro Energy (GWh)......  Hydrologic & generation forecast.
FE: Forecasted Energy Purchased (GWh)..  EA-HE.
FFC: Forecasted Avg Energy Price per     From commercially available price indices.
 MWh ($).
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 $0).
FARR: Additional Revenue to be           FX-FA.
 Recovered ($).
----------------------------------------------------------------------------------------------------------------
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     WL/EA * 100.
 SHP.
CRCE: CRC Energy (GWh).................  EA-WL.
CRCEP: CRC Energy Percentage of Full     CRCE/EA * 100.
 SHP.
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 non-reimbursable 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

[[Page 52993]]

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      Financial Statements.
 Expenses ($).
PFE: Prior Year Actual Firming      Financial Statements.
 Energy (GWh).
------------------------------------------------------------------------
STEP TWO: Determine the actual firming cost for the CRC portion
------------------------------------------------------------------------
EAC: Sum of the energy allocations
 of customers subject to the PYA
 (GWh).
FFC: Forecasted Firming Energy      From CRC Calculation.
 Cost ($/MWh).
AFC: Actual Firming Energy Cost ($/ PFX/PFE.
 MWh).
CRCEP: CRC Energy Percentage......  From CRC Calculation.
CRCE: Purchased Energy for the CRC  EAC*CRCEP.
 (GWh).
------------------------------------------------------------------------
STEP THREE: Determine Revenue Adjustment (RA) and PYA
------------------------------------------------------------------------
RA: Revenue Adjustment ($)........  (AFC-FFC)*CRCE*1,000.
PYA: Prior Year Adjustment (mills/  (RA/EAC)/1,000.
 kWh).
------------------------------------------------------------------------

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

[[Page 52994]]

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-to-Point 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:
[GRAPHIC] [TIFF OMITTED] TN12SE08.001

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 long-term 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

[[Page 52995]]

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-to-point 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:
[GRAPHIC] [TIFF OMITTED] TN12SE08.002

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-to-Point 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-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 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-to-point 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

[[Page 52996]]

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


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