[Federal Register Volume 70, Number 156 (Monday, August 15, 2005)]
[Notices]
[Pages 47823-47836]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 05-16044]


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DEPARTMENT OF ENERGY

Western Area Power Administration


Salt Lake City Area Integrated Projects-Rate Order No. WAPA-117

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of Order Concerning Power Rates.

-----------------------------------------------------------------------

SUMMARY: The Deputy Secretary of Energy confirmed and approved Rate 
Order No. WAPA-117 and Rate Schedule SLIP-F8, 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 provisional rates will be in effect until the Federal Energy 
Regulatory Commission (Commission) confirms, approves, and places them 
into effect on a final basis or until they are replaced by other rates. 
The provisional rates will provide sufficient revenue to pay all annual 
costs, including interest expense, and repayment of power investment 
and irrigation aid, within the allowable periods.

DATES: Rate Schedule SLIP-F8 will be placed into effect on an interim 
basis on the first day of the first full billing period beginning on or 
after October 1, 2005, and will be in effect until the Commission 
confirms, approves, and places the rate schedules in effect on a final 
basis through September 30, 2010, or until the rate schedule is 
superseded.

FOR FURTHER INFORMATION CONTACT: Mr. Bradley S. Warren, CRSP Manager, 
CRSP Management Center, Western Area Power Administration, P.O. Box 
11606, Salt Lake City, UT 84147-0606, (801) 524-6372, e-mail 
[email protected], or Ms. Carol Loftin, Rates Manager, CRSP Management 
Center, Western Area Power Administration, P.O. Box 11606, Salt Lake 
City, UT 84147-0606, (801) 524-6380, e-mail [email protected].

SUPPLEMENTARY INFORMATION: The Secretary of Energy approved existing 
Rate Schedule SLIP-F7 for SLCA/IP firm power on September 12, 2002 
(Rate Order No. WAPA-99). The Commission confirmed and approved the 
rate schedule on November 14, 2003, in FERC Docket No. EF02-5171-000. 
The existing rate schedule is effective from October 1, 2002, for a 5-
year period ending September 30, 2007.
    The existing firm power Rate Schedule SLIP-F7 is being superseded 
by Rate Schedule SLIP-F8. Under Rate Schedule SLIP-F7, the energy rate 
is 9.5 mills per kilowatthour (mills/kWh), and the capacity rate is 
$4.04 per kilowattmonth ($/kWmonth). The composite rate is 20.72 mills/
kWh. The provisional firm power rate consists of an energy charge of 
10.43 mills/kWh and a capacity charge of $4.43 per kWmonth. The 
provisional rates for SLCA/IP firm power in Rate Schedule SLIP-F8 will 
result in an overall composite rate of 25.28 mills/kWh on October 1, 
2005, and will result in an increase of about 22 percent when compared 
with the existing SLCA/IP

[[Page 47824]]

firm power composite rate under Rate Schedule SLIP-F7.
    The firm power rate will also include a cost recovery mechanism 
called a Cost Recovery Charge (CRC). The CRC is necessary to adequately 
maintain a sufficient cash balance in the Upper Colorado River Basin 
Fund in times of financial hardship. The CRC is a charge on Sustainable 
Hydropower (SHP) energy, as determined by financial conditions. Each 
May, Western will provide Customers with information concerning the 
anticipated CRC for the upcoming fiscal year. Firm power Customers may 
choose to take less firm energy, and in exchange Western will waive the 
CRC charge.
    By Delegation Order No. 00-037.00, effective December 6, 2001, the 
Secretary of Energy delegated: (1) The authority to develop power and 
transmission rates to Western's Administrator, (2) the authority to 
confirm, approve, and place such rates into effect on an interim basis 
to the Deputy Secretary of Energy, and (3) the authority to confirm, 
approve, and place into effect on a final basis, to remand or to 
disapprove such rates to the Commission. Existing DOE procedures for 
public participation in power rate adjustments (10 CFR part 903) were 
published on September 18, 1985.
    Under Delegation Order Nos. 00-037.00 and 00-001.00A, 10 CFR part 
903, and 18 CFR part 300, I hereby confirm, approve, and place Rate 
Order No. WAPA-117, the proposed SLCA/IP firm power rate, into effect 
on an interim basis. The new Rate Schedule SLIP-F8 will be promptly 
submitted to the Commission for confirmation and approval on a final 
basis.

    Dated: August 1, 2005.
Clay Sell,
Deputy Secretary.

Order Confirming, Approving, and Placing the Salt Lake City Area 
Integrated Projects Firm Power Rate Into Effect on an Interim Basis

    This rate was established in accordance with section 302 of the 
Department of Energy (DOE) Organization Act (42 U.S.C. 7152). This Act 
transferred to and vested in the 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 
Secretary of Energy delegated: (1) The authority to develop power and 
transmission rates to Western's Administrator, (2) the authority to 
confirm, approve, and place such rates into effect on an interim basis 
to the Deputy Secretary of Energy, and (3) the authority to confirm, 
approve, and place into effect on a final basis, to remand or to 
disapprove such rates to the Commission. Existing DOE procedures for 
public participation in power rate adjustments (10 CFR part 903) were 
published on September 18, 1985.

Acronyms and Definitions

    As used in this Rate Order, the following acronyms and definitions 
apply:

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.
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 CROD.
Commission: Federal Energy Regulatory Commission.
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.
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 MC: The CRSP Management Center of Western.
CUP: Central Utah Project.
Customer: An entity with a contract that is receiving firm electric 
service 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.
DPR: Definite Plan Report of the CUP.
EA: SHP Energy Allocation (GWh) as used in the CRC formula.
EAC: Sum of Customers' energy allocations subject to the PYA 
formula.
Energy: Measured in terms of the work it is capable of doing 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/kilowatthour and applied to each kilowatthour 
delivered to each Customer.
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 purchase energy as used in the CRC formula.
FERC: The Commission.
FFC: Forecasted Firming Energy Cost per MWh as used in the CRC and 
PYA formula.
Firm: A type of product and/or service guaranteed to be available in 
accordance with the terms of the contract.
FRN: Federal Register notice.
FX: Forecasted energy purchase expense as used in the CRC formula.
FY: Fiscal year; October 1 to September 30.
GWh: Gigawatthour--the electrical unit of energy that equals 1 
billion watthours or 1 million kWh.
HE: Forecasted hydro energy as used in the CRC formula.
Integrated Projects: The resources and revenue requirements of the 
Collbran, Dolores, Rio Grande, and Seedskadee projects blended 
together with the CRSP to create the SLCA/IP resources and rate.
kW: Kilowatt--the electrical unit of capacity that equals 1,000 
watts.
kWh: Kilowatthour--the electrical unit of energy that equals 1,000 
watts in 1 hour.
kWmonth: Kilowattmonth--the electrical unit of the monthly amount of 
capacity.
Load: The amount of electric power or energy delivered or required 
at any specified point(s) on a system.
M&I: Municipal and Industrial water.
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.
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: Net Revenue. Revenue remaining after paying all annual expenses 
as used in the CRC formula.
O&M: Operation and Maintenance.
OM&R: Operation, Maintenance & Replacements.
PAE: Projected Annual Expenses as used in the CRC formula.
PAR: Projected Annual Revenue ($) without CRC as used in the CRC 
formula.
Participating Projects: The Dolores and Seedskadee projects 
participating with CRSP according to the CRSP Act of 1956.

[[Page 47825]]

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 equal cumulative revenues.
Power: Capacity and energy.
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.
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 February 
2005.
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, these 
laws create the originating framework under which Western markets 
power.
Revenue Requirement: The revenue required to recover annual 
expenses, such as O&M, purchase power, transmission service 
expenses, interest, deferred expenses, and repayment of Federal 
investments, and other assigned costs.
SHP: Sustainable Hydropower.
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.
USDA: United States Department of Agriculture.
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: The Work Program Review is a draft estimate of costs that are 
expected to be included in the Congressional Budget for Western and 
Reclamation.
WRP: Western Replacement Power.

Effective Date

    The new interim rates will take effect on the first day of the 
first full billing period beginning on or after October 1, 2005, and 
will remain in effect until September 30, 2010, pending approval by the 
Commission on a final basis.

Public Notice and Comment

    Western followed the Procedures for Public Participation in Power 
and Transmission Rate Adjustments and Extensions, 10 CFR part 903, in 
developing these rates. The steps Western took to involve interested 
parties in the rate process were:
    1. The proposed rate adjustment process began October 6, 2004, when 
Western mailed a notice announcing an informal Customer meeting on 
October 27, 2004, to all SLCA/IP Customers and interested parties.
    2. On October 27, 2004, beginning at 1:30 p.m., an informal 
Customer meeting was held to discuss the components and rationale for 
the rate adjustment, present a rate design, and answer questions.
    3. A Federal Register notice published on January 18, 2005 (70 FR 
2858), announced the proposed rate adjustment for SLCA/IP. This 
publication began a public consultation and comment period, and 
announced the public information and public comment forums.
    4. On February 7, 2005, Western's CRSP MC mailed letters to all 
SLCA/IP preference Customers and interested parties transmitting the 
Brochure for Proposed Rates.
    5. On February 23, 2005, beginning at 1:30 p.m., Western held a 
public information forum at the Quality Inn, Salt Lake City Airport in 
Salt Lake City, Utah. Western provided detailed explanations of the 
proposed SLCA/IP rates. Western provided rate brochures, supporting 
documentation, and informational handouts.
    6. On March 30, 2005, beginning at 1:30 p.m., Western held a 
comment forum at the Quality Inn, Salt Lake City Airport in Salt Lake 
City, Utah, to give the public an opportunity to comment for the 
record. Five individuals commented at this forum.
    7. Western received 21 comment letters during the consultation and 
comment period, which ended April 18, 2005. All formally submitted 
comments have been considered in preparing this Rate Order.
Comments
    Written comments were received from the following organizations: 
Ak-Chin Tribe, Arizona, Aspen City, Colorado, Bureau of Reclamation, 
Upper Colorado Region, Utah, Colorado River Commission of Nevada, 
Nevada, Colorado River Energy Distributors Association, Arizona, 
Colorado Springs Utility, Colorado, Deseret Power Electric Cooperative, 
Utah, Dolores Water Conservancy District, Colorado, Fleming City, 
Colorado, Gunnison City, Colorado, Holyoke City, Colorado, Irrigation & 
Electrical Districts Association of Arizona, Arizona, Mt. Wheeler 
Power, Inc., Nevada, Navajo Tribal Utility Authority, Arizona, Oak 
Creek, Town, Colorado, Ocotillo Water Conservation District, Arizona, 
Platte River Power Authority, Colorado, Salt River Project, Arizona, 
Tri-State Generation and Transmission Association, Inc., Colorado, Utah 
Associated Municipal Power Systems, Utah, and White Mountain Apache 
Tribe, Arizona.
    Representatives of the following organizations made oral comments: 
Colorado River Energy Distributors Association, Arizona, Deseret Power 
Electric Cooperative, Utah, Dolores Water Conservancy District, 
Colorado, Garkane Energy Incorporated, Utah, Utah Associated Municipal 
Power Systems, Utah.

Project Description

    The SLCA/IP consists of the CRSP and the 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 revenue requirement. Repayment criteria are based on law, 
policies including DOE Order RA 6120.2, and authorizing legislation.
    Proposed rates for SLCA/IP firm power result in an overall 
composite rate increase of approximately 22 percent on October 1, 2005, 
when compared to the existing SLCA/IP firm power rates in Rate Schedule 
SLIP-F7. The current composite rate under Rate Schedule SLIP-F7 is 
20.72 mills/kWh; however, in actuality this effective composite rate is 
25.10 mills/kWh as a result of a decrease in the contractual amount of 
electrical service provided to the firm power Customers beginning in FY 
2005. The proposed composite rate is 25.28 mills/kWh. The following 
table

[[Page 47826]]

compares the current and proposed firm power rates:

           Comparison of Current and Proposed Firm Power Rates
------------------------------------------------------------------------
                                                Proposed
                                Current rate      rate        Increase
------------------------------------------------------------------------
Rate Schedule.................    SLIP-F7       SLIP-F8     ............
Energy (mills/kWh)............          9.50         10.43           .93
Capacity ($/kW month).........          4.04          4.43           .39
Composite Rate (mills/kWh)....         20.72         25.28          4.56
------------------------------------------------------------------------

Cost Recovery Charge

    Over the last several years, hydropower generation production has 
been lower than expected, and purchased power prices have been higher 
than forecasted. Reduced hydropower generation, due to extended drought 
conditions in the region, has caused actual purchase power expenses to 
be significantly higher than forecasts, resulting in cost-recovery 
issues for the Basin Fund.
    In the proposed Ratesetting PRS, purchased power expense beyond the 
initial 5-year cost evaluation period has been reduced in anticipation 
that return-to-normal water conditions will result in Western meeting 
its firm power commitments through hydropower generation. However, in 
the event that expenses significantly exceed estimates and in order to 
adequately recover and maintain a sufficient balance in the Basin Fund, 
Western proposes to implement a CRC on all SHP energy.
    The CRC is strictly a Basin Fund cash analysis and is outside of 
the PRS calculations. In calculating the CRC, Western will forecast the 
amount of revenue available in the Basin Fund to purchase the energy 
necessary to deliver the yearly SHP energy commitment in the next FY. 
Western will estimate the availability of revenue in the Basin Fund, at 
the beginning and end of the FY, to maintain a BFTB for the following 
year, and to limit the annual loss to the Basin Fund. The BFTB will be 
equal to 15 percent of the upcoming year's total expenses but not less 
than $20 million. The allowable annual loss is limited to no more than 
25 percent of the BFBB. Once Western determines the amount of revenue 
available in the Basin Fund for anticipated expenses, it will determine 
if additional revenue is needed and will include this amount in the 
Customers' firm power bill through the assessment of a CRC. All 
expenses are considered in the CRC, with the exception of non-
reimbursable program expenses, which are limited to $25 million per 
year, indexed for inflation. This limitation is for CRC formula 
calculation purposes only, and is not a cap on actual non-reimbursable 
expenses.

Calculation of the CRC

    Western will forecast the amount of purchased energy necessary to 
deliver SHP energy, the corresponding expense, and determine the funds 
available for firming purchases. In determining the forecasted funds 
available, the impact on Net Revenue (projected annual revenue less 
projected annual expenses), and the Basin Fund Net Balance (Basin Fund 
FY beginning balance plus net revenue) will be analyzed. If the impact 
on both of these fall short of the revenue and balance triggers 
described above, the CRC will not apply during that FY. If the impact 
on either net revenue or the Basin Fund balance is greater than the 
allowable limits, the smaller factor will be used to determine the 
additional revenue requirements. For FY 2006, the CRC charge is 0.0 
mills/kWh. For purposes of explaining how the CRC is calculated, the 
following example is provided:

                                             Sample CRC Calculation
----------------------------------------------------------------------------------------------------------------
                                          Description                                      Formula \1\
----------------------------------------------------------------------------------------------------------------
                        Step One.--Determine the Net Balance Available in the Basin Fund
----------------------------------------------------------------------------------------------------------------
BFBB............................  Basin Fund Beginning              $27,900,000  Financial forecast.
                                   Balance ($).
BFTB............................  Basin Fund Target Balance         $27,665,550  $.15 * PAE (not less than $20
                                   ($).                                           million).
PAR.............................  Projected Annual Revenue         $165,984,000  Financial forecast.
                                   ($) w/o CRC.
PAE.............................  Projected Annual Expense         $184,437,000  Financial forecast.
                                   ($).
NR..............................  Net Revenue ($)............     $(18,453,000)  PAR-PAE.
NB..............................  Net Balance ($)............        $9,447,000  BFBB + NR.
---------------------------------
                          Step Two.--Determine the Forecasted Energy Purchase Expenses
----------------------------------------------------------------------------------------------------------------
EA..............................  SHP Energy Allocation (GWh)             4,655  Customer contracts.
HE..............................  Forecasted Hydro Energy                 4,218  Hydrologic & generation
                                   (GWh).                                         forecast.
FE..............................  Forecasted Energy Purchase                427  EA-HE.
                                   (GWh).
FFC.............................  Forecasted Avg. Energy                 $55.50  From commercially available
                                   Price per MWh ($).                             price indices.
FX..............................  Forecasted Energy Purchase        $24,253,500  PE * FFC.
                                   Expense ($).
---------------------------------
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 Leader of the Two Will Be
                                                      Used
----------------------------------------------------------------------------------------------------------------
FA1.............................  Based Fund Balance Factor          $6,034,950  If (NB > BFBB, FX, FX- (BFTB-
                                   ($).                                           NB)).

[[Page 47827]]

 
FA2.............................  Revenue Factor ($).........       $12,775,500  If (NR > -.25*BFBB, FX, FX + NR
                                                                                  +.25*BFBB).
FA..............................  Funds Available ($)........        $6,034,950  Lesser of FA1 or FA2 (not less
                                                                                  than $0).
FARR............................  Additional Revenue to be          $18,218,550  FX-FA.
                                   Recovered ($).
---------------------------------
    Step Four.--Once the FA for Purchases Have Been Determined, the CRC Can Be Calculated, and the WL Can Be
                                                   Determined
----------------------------------------------------------------------------------------------------------------
WL..............................  Waiver Level (GWh).........             4,327  If (EA > HE, EA, HE + (FE*(FA/
                                                                                  FX))), but not less than HE.
WLP.............................  Waiver Level Percentage of                93%  WL/EA*100.
                                   Full SHP.
CRCE............................  CRC Energy (GWh)...........               328  EA-WL.
CRCEP...........................  CRC Energy Percentage of                   7%  CRCE/EA*100.
                                   Full SHP.
CRC.............................  Cost Recovery Charge (mills/             3.91  FARR/(EA*1,000).
                                   kWh).
----------------------------------------------------------------------------------------------------------------
\1\ Some formulas in this table are based on standard Excel spreadsheet formatting.

Narrative CRC Example

Step One: Determine the Net Balance Available in the Basin Fund
    BFBB--Determine the Basin Fund Beginning Balance for next FY. In 
this example, Western estimates that the BFBB will be $27,900,000.

BFBB = $27,900,000

    BFTB--Determine the Basin Fund Target Balance for the next FY. The 
BFTB is 15 percent of Projected Annual Expenses for the coming FY, but 
will not be less than $20 million.

BFTB = 0.15 * PAE
BFTB = 0.15 * $184,437,000
BFTB = $27,665,550

    PAR-Projected Annual Revenue is an estimate of revenue for the next 
FY.

PAR = $165,984,000

    PAE--Projected Annual Expense is an estimate of total cash outlay 
from the Basin Fund for the next FY. The PAE includes all cash outlay 
from the Basin Fund including non-reimbursable expenses, which are 
capped at $25 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.

PAE = $184,437,000

    NR--Net Revenue equals Projected Annual Revenues minus Projected 
Annual Expenses.

NR = PAR-PAE
NR = $165,984,000-$184,437,000
NR = ($18,453,000)

    NB--Net Balance is the Basin Fund Beginning Balance plus Net 
Revenue.
NB = BFBB + NR
NB = $27,900,000 + ($18,453,000)
NB = $9,447,000
Step Two: Determine the Forecasted Energy Purchase Expenses
    EA--The Sustainable Hydropower Energy Allocation. This does not 
include Project Use Customers.

EA = 4,655 GWh

    HE--The forecasted Hydro Energy available during the next FY.

HE = 4,218 GWh

    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
FE = 4,655-4,218
FE = 437 GWh

    FFC--The forecasted energy price for the next FY per MWh based on 
commercially available price indices.

FFC = $55.50/WHh

FX--Forecasted Energy purchase power expenses based on the current year 
April 24-month study, representing an estimate of the total cost of 
firming purchases for the coming FY.

FX = FE * FFC * 1,000
FX = 437 * $55.50 * 1,000
FX = $24,253,500
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. Funds Available Shall Not Be Less Than Zero
A. Basin Fund Balance Factor (FA1)
    The first formula 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 the value for 
forecasted energy purchase power expenses is used. If the net balance 
is less than the Basin Fund Target Balance, then reduce the value of 
the forecasted energy purchase 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)

    Since the Net Balance, $9,447,000, is less than the Basin Fund 
Target Balance, $27,665,550,

FA1 = FX-(BFTB-NB)
FA1 = $24,253,500-($27,665,550-$9,447,000)
FA1 = $6,034,950
B. Basin Fund Revenue Factor (FA2)
    The second factor ensures that Net Revenue does not result in a 
loss that exceeds 25 percent of the Basin Fund Beginning Balance. If 
Net Revenue is greater than a minus 25 percent of the Basin Fund 
Beginning Balance, then use the value for Forecasted Energy Purchase 
Expense. 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 Balance to the FX.

FA2 = If (NR > -0.25 * BFBB, FX, FX + NR + 0.25 * BFBB)

If the NR does not result in a loss that exceeds 25 percent of the 
BFBB, then

FA2 = FX

    If the NR results in a loss that exceeds 25 percent of the BFBB, 
then

FA2 = FX + NR + 0.25 * BFBB

    Since NR ($18,453,000) is less than a minus 25 percent of BFBB 
($6,975,000)

FA2 = FX + NR + 0.25 * BFBB

[[Page 47828]]

FA2 = $24,253,500 + ($18,453,000) + $6,975,000
FA2 = $12,775,500

    FA--Determine the Funds Available by using the lesser of FA1 and 
FA2.

FA1 = $6,034,950
FA2 = $12,752,000
FA = FA1
FA = $6,034,950

    FARR--Calculate the additional revenue to be recovered by 
subtracting the Funds Available from the forecasted energy purchase 
power expenses.

FARR = FX-FA
FARR = $24,253,500-$6,034,950
FARR = $18,218,550
Step Four: Once the Additional Revenue To Be Recovered Has Been 
Determined, the Cost Recovery Charge Can Be Calculated, and the Waiver 
Level Can Be Determined
A. Cost Recovery Charge (CRC)
    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
CRC = $18,218,550/4655
CRC = 3.91 mills/kWh

B. Waiver Level (WL)
    The WL provides Customers the ability for Western to reduce 
purchased power expenses by scheduling less energy than their 
contractual amount. 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.
    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 + (FE * (FA/FX)))

    If SHP Energy Allocation is less than forecasted HE available, then

WL = EA

    If SHP Energy Allocation is greater than forecasted HE available, 
then

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

    Since HE 4,218 is less than SHP Energy Allocation, 4,655,

WL = HE + (FE * (FA/FX))
WL = 4,218 + (437 * ($6,034,950/$24,253,500))
WL = 4,327 GWh

Prior Year Adjustment (PYA) Calculation

    Since the annual determination of the CRC is based upon estimates, 
an annual PYA will also be calculated when the CRC is applied. The PYA 
will be applied to those Customers who were charged the CRC. 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. Because there will not be a CRC for FY 
2006, the PYA will not be needed in 2007. Below is an example of a PYA 
calculation.

                         Sample 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 FY
------------------------------------------------------------------------
PFX.................  Prior Year            $27,950,000  Financial
                       Actual Firming                     Statements.
                       Expenses ($).
                  PF  Prior Year                    475  Financial
                   E.  Actual Firming                     Statements.
                       Energy (GWh).
---------------------
    Step Two--Determine the Actual Firming Cost for the CRC Portion.
------------------------------------------------------------------------
EAC.................  Sum of the                  2,500
                       energy
                       allocations of
                       Customers
                       subject to the
                       PYA (GWh).
FFC.................  Forecasted                  55.50  From CRC
                       Firming Energy                     Calculation.
                       Cost--($/MWh).
AFC.................  Actual Firming              58.84  PFX/PFE.
                       Energy Cost--
                       ($/MWh).
CRCEP...............  CRC Energy                     7%  From CRC
                       Percentage.                        Calculation.
CRCE................  Purchased                     176  EAC*CRCEP.
                       Energy for the
                       CRC (GWh).
---------------------
         Step Three--Determine Revenue Adjustment (RA) and PYA.
------------------------------------------------------------------------
RA..................  Revenue                  $589,198  (AFC-FFC)*CRCE*
                       Adjustment ($).                    1,000.
PYA.................  Prior Year                   0.24  (RA/EAC)/1,000.
                       Adjustment
                       (mills/kWh).
------------------------------------------------------------------------

Narrative PYA Example Only (Assumes That a CRC Was needed for the 
Previous Year)

Step One: Determine actual expenses and purchases for previous year's 
firming. This data will be obtained from Western's financial statements 
at end of FY.
    PFX--Prior year actual firming expense,

PFX = $27,950,000

    PFE--Prior year actual firming energy,

PFE = 475 GWh
Step Two: Determine the actual firming cost for the Cost Recovery 
Charge portion.
    EAC--Sum of the energy allocations of Customers who were assessed 
the Cost Recovery Charge for the prior year.

EAC = 2,500 GWh

    CRCE--The amount of CRC Energy needed, so

CRCE = EAC * CRCEP
CRCE = 2500 * .07
CRCE = 176 GWh

    AFC--The Actual Firming Energy Cost is the PFX divided by the PFE

AFC = (PFX / PFE) / 1,000
AFC = ($27,950,000 / 475) / 1,000
AFC = $58.84
Step Three: Determine Revenue Adjustment and PYA.
    RA--The Revenue Adjustment is Actual Firming Energy Cost less 
Forecasted Firming Energy Cost times Purchased Energy for the CRC.

RA = (AFC-FFC) * CRCE * 1,000
RA = ($58.84-$55.50) * 176 * 1,000
RA = $589,198

    PYA--The PYA is the Revenue Adjustment divided by the SHP Energy

[[Page 47829]]

Allocation for the Cost Recovery Charge Customers only.

PYA = (RA / EAC) / 1,000
PYA = ($589,198 / 2,500) / 1,000
PYA = .24 mills/kWh

    The Customers' PYA will be based on their prior year's energy 
multiplied by the PYA mills/kWh to determine the dollar value that will 
be assessed. The Customer 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 
each 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).
    CRC Schedule: Western will provide its Customers with information 
concerning the anticipated CRC each May prior to the beginning of the 
effective FY. 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, notifying Customers of the CRC, and the deadline for 
requesting a waiver of the CRC. This schedule has been changed to 
reflect Customer concerns that the proposed schedule did not allow them 
enough time to make a decision about requesting a waiver of the CRC.

                              CRC Schedule
------------------------------------------------------------------------
                   Task                            Date each year
------------------------------------------------------------------------
April 24--Month Study (Forecast to Model    April 1.
 Projections).
CRC Notice to Customers...................  May 1.
Waiver Request Submitted By Customers.....  June 15.
Schedules Effective.......................  October 1.
------------------------------------------------------------------------

Existing and Provisional Rates

    A comparison of the existing and provisional firm power rates 
follows:

   Comparison of Existing and Provisional Salt Lake City Area/Integrated Projects Firm Power and Cost Recovery
                                                     Charge
----------------------------------------------------------------------------------------------------------------
                                     Current rate  October 1, 2003-  Proposed rate  October 1, 2005-   Percent
           Rate schedule              September 30, 2007  (SLIP-F7)   September 30, 2010  (SLIP-F8)     change
----------------------------------------------------------------------------------------------------------------
Energy (mills/kWh).................  9.5...........................  10.43.........................           10
CRC (if applicable)................  N/A...........................  varies........................  ...........
Total Energy Charge................  9.5...........................  varies........................          N/A
Capacity ($/kWmonth)...............  4.04..........................  4.43..........................           10
----------------------------------------------------------------------------------------------------------------

Certification of Rates

    Western's Administrator certified that the interim rates for SLCA/
IP firm power 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 operation, maintenance, 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-
F7 expires September 30, 2007, a new rate to recover increased costs 
will be effective October 1, 2005, and Rate Schedule SLIP-F7 will be 
superseded by the new rates in Rate Schedule SLIP-F8. The provisional 
rates for SLCA/IP firm power consist of a capacity rate and an energy 
rate. The provisional capacity rate is $4.43 per kWmonth, and the 
provisional energy rate is 10.43 mills/kWh.

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 2006-FY 2010) Total Revenues and Expenses
----------------------------------------------------------------------------------------------------------------
                                                                  Existing rate   Proposed rate     Difference
                                                                     ($000)          ($000)           ($000)
----------------------------------------------------------------------------------------------------------------
Total Revenues.................................................        $775,642        $815,494         $39,852
----------------------------------------------------------------
 
                                               Revenue Distribution
----------------------------------------------------------------------------------------------------------------
 
 Expenses:
    O&M........................................................         292,755         305,198          12,443
    Purchased Power and Wheeling...............................          55,426         131,529          76,103
    Integrated Projects Requirements...........................          45,250          38,582          (6,668)
    Interest...................................................         134,559          80,003         (54,556)
    Other......................................................          19,660          18,488          (1,172)
                                                                -----------------
        Total Expenses.........................................         547,650         573,800          26,150
Principal Payments:
    Capitalized Expenses (deficits)............................               0               0               0
    Original Project and Additions.............................         214,278          99,970        (114,308)
    Replacements...............................................          13,714         141,724         128,010
    Irrigation.................................................               0               0               0
        Total Principal Payments...............................         227,992         241,694          13,702
                                                                -----------------

[[Page 47830]]

 
        Total Revenue Distribution.............................         775,642         815,494          39,852
----------------------------------------------------------------------------------------------------------------

Basis for Rate Development

    The existing rates for SLCA/IP firm power in Rate Schedule SLIP-F7 
no longer provide sufficient revenues to pay all annual costs, 
including interest expense, and repay investment and irrigation aid 
within the allowable periods. The adjusted rates reflect increases 
primarily in O&M costs, purchase power costs, and a reduction in energy 
sales. The costs are offset by changes in interest and principal 
payments that are a result of a reconstruction of the PRS that ensured 
all principal payments and interest were applied correctly in the PRS. 
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. The provisional rates 
will take effect on October 1, 2005, to correspond with the start of 
the Federal FY, and will remain in effect through September 30, 2010.
    Provisions for transformer losses adjustment, power factor 
adjustment, WRP administrative charge, and Customer Displacement Power 
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 
SLIP-F7.

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 clarification where necessary. The rate process issues 
discussed are (1) Base Rate and (2) Cost Recovery Charge.
1. Base Rate
    A. Comment: A Customer representative wanted to know if the 
salinity costs of the USDA were in the FY 2006 President's Budget and 
if the same amount is being used in the PRS.
    Response: The USDA and Natural Resource Conservation Service 
salinity program costs are included in the FY 2006 President's Budget. 
The total Upper Basin Fund obligation for salinity in the FY 2006 
President's Budget is estimated at $2.2 million, which includes 
Reclamation's salinity program costs. Expenses included in the 
Ratesetting PRS are from the FY 2006 WPR, which included $2.6 million 
for salinity program costs. The minimal reduction in the FY 2006 
President's Budget for salinity costs would have almost no impact on 
the firm power rate. This would impact the rate less than .01 mill/kWh.
    B. Comment: A Customer group requests the final CUP DPR for the 
Bonneville Unit be included in the PRS and costs allocated to temporary 
irrigation be reclassified as M&I for repayment purposes. Another 
commenter was concerned about using the DPR in the PRS stating that the 
DPR has a significant impact on the proposed rate, yet the costs 
associated with the DPR are tentative, with cost estimates based on 
preliminary engineering designs and final cost allocations remaining 
uncertain. To reduce the impact of the DPR on the rate, a Customer 
group recommended that all costs in the final DPR allocated to 
irrigation be included beyond the ratesetting period. The commenter 
suggested that the DPR should be incorporated into a future PRS when 
the numbers are more certain.
    Response: The results of the Final Supplement to the 1988 DPR for 
the Bonneville Unit of the CUP have been included in the PRS and are 
final numbers from Reclamation. In the draft Bonneville Unit DPR, there 
was mention of a block of water (temporary irrigation) amounting to 
20,000 A.F. The DPR mentioned that this water has been used for 
irrigation since 1996 and would continue through 2030. In 2030, this 
20,000 A.F. would be converted to M&I use, along with 10,000 additional 
A.F. earmarked for M&I use. The 30,000 A.F. would be used for M&I 
through the remainder of the evaluation period (FY 2115). The draft DPR 
used an accounting method that compared the allocation of the water 
between irrigation and M&I water as follows:

----------------------------------------------------------------------------------------------------------------
                                                                    Irrigation          M&I            Total
----------------------------------------------------------------------------------------------------------------
Acre--Feet......................................................          20,000          30,000          50,000
Percent.........................................................             40%             60%            100%
----------------------------------------------------------------------------------------------------------------

    These percentages, as shown in the table above, were used to 
allocate ``assigned joint costs'' between irrigation and M&I in the 
draft DPR. The draft DPR added the benefit (water) used by irrigation 
and the total water eventually used by M&I and computed a percent of 
each to the sum of the two or total water use. Irrigation's use of the 
water was 20,000 A.F., and M&I's was 30,000 A.F. for a total of 50,000 
A.F. This was incorrect since there is only a total of 30,000 A.F. 
(20,000 A.F. initially used by irrigation and the 10,000 A.F. reserved 
for M&I use that was never used by irrigation). The final DPR now 
included in the PRS uses a present value of water supply approach. This 
brings the two uses of the water back to a present value based on 
historical and future use. The present values were compared to each 
other for allocation purposes as follows:

----------------------------------------------------------------------------------------------------------------
                                                                    Irrigation          M&I            Total
----------------------------------------------------------------------------------------------------------------
Acre--Feet......................................................         293,598         318,383         611,981
Percent.........................................................          47.98%          52.02%            100%
----------------------------------------------------------------------------------------------------------------


[[Page 47831]]

    In the final DPR, weight is given to the timing and uses of the 
temporary irrigation water. The present value method, as opposed to the 
method used in the draft DPR, actually yields an increase in the 
percentage allocation to irrigation.
    C. Comment: Several Customers commented that they support Western's 
inclusion of $2 million per year of purchased power costs in the PRS in 
those years beyond FY 2009.
    Response: Western appreciates the support. As discussed in the rate 
brochure, Western has provided notice to its Customers that it may 
change the SHP allocations in FY 2009 to where little or no purchased 
power costs will be necessary except for operational purposes. Western 
will continue to work with its Customers and provide ample notice 
regarding SHP allocations.
    D. Comment: A Customer representative encouraged Western to 
consider potential rate and cash flow impacts prior to including 
expenses such as replacement of the Flaming Gorge transformers in its 
WPR. The representative stated the purpose and intent of the 1992 WPR 
and joint transmission planning principles are to promote ``rate impact 
planning,'' so full consideration is given to potential project and 
rate impacts prior to decisions being made to include the costs in CRSP 
WPR documents. Specifically, Western should provide study results 
identifying the cause of the overload condition at Flaming Gorge and 
should actively seek cost sharing from other entities in the affected 
region prior to including the full cost of the transformers in the WPR. 
In addition, several Customers believe that Western needs to reduce its 
O&M and construction costs, including travel expenses.
    Response: Replacement of the Flaming Gorge transformers is 
necessary due to system overload conditions. Western believes these 
replacements are necessary to keep the system intact. On June 28, 2005, 
Western hosted a meeting with all of the affected parties to discuss 
the history of the Flaming Gorge transformers as well as the operating 
history under steady-state and N-1 outage conditions. Western will 
continue to work with the affected parties as part of the process for 
replacing the Flaming Gorge transformers. The rate impact of including 
a $3 million replacement cost in FY 2006 is approximately .02 mills/
kWh. Western will continue to pursue cost-reduction opportunities; 
however, it must also maintain system reliability. Western believes the 
WPR process it conducts with its Customers has been beneficial in 
reducing both Reclamation's and Western's O&M and Construction costs. 
Western will continue to look for ways to reduce its O&M costs and 
consult with Customers on program costs. Travel expenses are being 
managed carefully, and discretionary travel is being deferred and/or 
conference calls are being used more frequently.
    E. Comment: Several Customers suggest that Western and Reclamation 
suspend CRSP power revenue contributions to ``discretionary'' 
environmental programs during drought conditions and seek alternative 
sources of funding, such as appropriations. To the extent the agencies 
can influence actual spending for the Colorado River Basin Salinity 
Control Program, they should urge reduced spending during drought 
conditions. In addition, the agencies should not support or implement 
experimental or operational changes that have a negative impact on the 
Basin Fund cash flow during periods of drought.
    Response: Western and Reclamation also support the concept of 
seeking alternative sources of funding to assist with funding shortages 
resulting from the continuing drought and will work with power 
Customers and other interests in seeking acceptable solutions; however, 
Western and Reclamation do not believe their obligation to fund the 
environmental programs is discretionary.
    F. Comment: A Customer group recommends that Western adopt a policy 
of solving the PRS to the nearest 100th of a mill as opposed to 
rounding the rate up to the nearest 10th of a mill.
    Response: Western agrees and has solved the proposed rate to the 
nearest 100th of a mill.
    G. Comment: A Project Use Customer commented that irrigators are 
getting a ``double hit,'' meaning that they have no water and their 
Project Use rates are going up 25 to 30 percent. The commenter asked 
that Western and Reclamation explore other options.
    Response: Western does not directly charge Project Use Customers. 
Reclamation determines this charge. Historically, Reclamation has 
chosen to charge Project Use Customers the same rate as Western charges 
its firm power Customers. Project Use Customers will see an increase of 
10 percent because their energy allocations have not been reduced like 
firm electric service Customers.
    H. Comment: A Customer stated that Reclamation's Upper Colorado 
Region's Project Use rate (UCP-2) should not be increased so that it 
equals the proposed SLCA/IP rate. The Customer further stated that the 
practice of having Reclamation's rate equaling the SLCA/IP rate should 
be discontinued and that participating irrigation projects should be 
given relief from the proposed rate increase.
    Response: Project Use Customers are currently charged under 
Reclamation rate schedule UCP-2. Reclamation determines this rate.
    I. Comment: Some Customers commented that much of the impetus for 
the proposed rate increase stems from the acceleration of the pinch-
point year from FY 2060 to FY 2025.
    Response: The change in the pinch point is not a cause for the rate 
increase. The current SLCA/IP firm power rate PRS has two pinch-point 
years, the dominant one in FY 2060 and a secondary one in FY 2025. 
These pinch points are caused by project repayment obligations. These 
obligations stem mostly from requirements of the CUP Bonneville Unit 
irrigation blocks.
    In the current Ratesetting PRS, repayment of the Duchesne block of 
the Bonneville Unit is due in FY 2025 and amounts to $104.8 million. 
The Southern Utah County and Juab-Mona-Nephi blocks come due with 
obligations of $152.3 million and $205.6 million in FY 2057 and FY 
2060, respectively.
    As a result of the changes in the final DPR, the revised 
Ratesetting PRS shows that the Duchesne block due in FY 2025 is reduced 
to $97.5 million, and the Southern Utah County and Juab-Mona-Nephi 
blocks are replaced by the Starvation block of $13.7 million in FY 
2055, the Southern Utah County block of $91.2 million in FY 2057, and 
the Uintah Basin Replacement block of $11.4 million also in FY 2057.
    In summary, the Duchesne block is reduced by $7.3 million in FY 
2025, and the other blocks in and around FYs 2055-2060 are reduced by 
$241.6 million, from $357.9 million to $116.3 million.
    These changes cause the Duchesne block of $97.5 million due in FY 
2025 to become the primary pinch point in the revised PRS. The pinch-
point year that previously occurred in FY 2060 no longer affects the 
rate. The FY 2025 pinch-point decrease of $7.3 million has the effect 
of reducing the firm power rate by 0.25 mills per kWh.
    J. Comment: A few Customers requested that Western use the most up-
to-date purchase power estimates in the PRS.
    Response: The future purchased power estimates for FY 2007-2009 
have been updated by using the long-term hydrology projections current 
as of April 13, 2005. FY 2006 purchased power estimates are based on

[[Page 47832]]

Reclamation's April 2005 24-month study.
2. Cost Recovery Charge
    A. Comment: Several Customers commented that the time schedule for 
determining if they wanted to request a waiver of the CRC was too 
short; they suggested that they be given at least 1 month to respond.
    Response: Western agrees and has changed the schedule. The CRC 
notice will be provided to the Customers on May 1 of each year, and the 
Customers will have until June 15 of each year to request a waiver.
    B. Comment: A Customer suggested the CRC be added to the base rate 
so there would be a single energy rate.
    Response: Western will apply the CRC only when it is needed during 
financial hardship situations. This approach is beneficial to the 
Customers because the Customers can avoid the CRC by taking less 
energy.
    C. Comment: Several Customers expressed concern that the CRC should 
be tied to purchase power costs only instead of all costs. They are 
concerned that Reclamation and Western will be able to put other 
expenses into the CRC.
    Response: The expenses that are included in the CRC calculation are 
Congressional Budget amounts for that current year. These expenses have 
been reviewed by the Customers, OMB, and Congress each year. 
Specifically, by Attachment No. 5 of the SLCA/IP contracts, Customers 
participate in the WPR. Western and Reclamation will continue to 
consult with Customers on program cost and formulate work plans through 
the review process. A PRS is calculated each year to determine if the 
current rate is sufficient to repay all costs within the allowable time 
period throughout the ratesetting period. If not, then Western will 
begin a rate process.
    D. Comment: A Customer commented that the composite rate had been 
approximately 28 mills/kWh in previous proposals; but after the CRC was 
proposed, the composite rate dropped to approximately 25 mills/kWh. The 
Customer asked how much of that drop was attributable to the CRC 
proposal versus changes in cost.
    Response: The composite rate was projected to be 28.65 mills/kWh 
during the informal rate process; it is now 25.28 mills/kWh. This is a 
difference of 3.37 mills/kWh. A reduction in aid-to-irrigation costs 
reduced the rate by .25 mills/kWh. The remaining 3.12 mills/kWh 
reduction was primarily due to lower purchase power costs estimates. In 
the proposed Ratesetting PRS, purchased power expense beyond the 
initial 5-year, cost-evaluation period has been reduced in anticipation 
that return-to-normal water conditions will result in Western meeting 
its firm power commitments through hydropower generation. In addition, 
Western has provided notice to its Customers that it may change the SHP 
allocations in FY 2009 to where little or no purchased power costs will 
be necessary except for operational purposes.
    E. Comment: A Customer asked for clarification of Western's 3-year 
strategic purchase plan for firming energy. The Customer also asked if 
Customer input would be involved before making these purchases.
    Response: In order to guard against rising energy prices, Western 
is considering making some purchases on a 3-year cycle. Western will 
consult with Customers when developing the details of this plan.
    F. Comment: A Customer group suggested that the BFTB should not be 
fixed at $30 million. The BFTB should be a fluid number that would 
change with varying circumstances (e.g. hydrology, market prices, 
replacements, non-reimbursable expenses, etc.). Another Customer noted 
that rather than maintaining the lower limit of the Basin Fund at $30 
million, the Basin Fund could be set at $15 million during drought 
periods to help stabilize rates and provide additional firming energy 
during drought conditions.
    Response: Western agrees that the BFTB should vary based on 
financial conditions and, therefore, has revised the BFTB to be 15 
percent of the total cash-outlay target for the upcoming FY, but not 
less than $20 million. For example, FY 2006 forecasted expenses are 
$151 million. Fifteen percent of this sum is $22.7 million. The 
calculated amount will be included in the yearly CRC proposal sent to 
the Customers on May 1 of each year.
    G. Comment: Several Customers requested that non-reimbursable costs 
included in the CRC's annual-projected expenses be reduced to zero 
before any reduction in purchase power expense occurred. Another 
Customer stated that the CRC discriminates against Customers and is 
arbitrary because it only reduces purchase power costs, while other 
controllable costs, such as non-reimbursable expenses, are given 
priority at the expense of Customers paying higher rates.
    Response: The CRC was developed to help reduce financial hardship 
in the Basin Fund; therefore, all revenues and all expenses need to be 
considered when determining the CRC. Western recognizes that non-
reimbursable expenses can have considerable impact on the CRC rate and, 
therefore, has revised its formula to cap the non-reimbursable expense 
included in the CRC calculation at $25 million each year, plus the cost 
of inflation. The CRC is charged to all Customers receiving their full 
SHP entitlements. Western will grant a waiver of the CRC to those 
Customers who voluntarily schedule no more than their proportionate 
share of the energy at the WL for a given year. Granting a waiver to an 
individual Customer neither increases nor decreases the CRC charge to 
other Customers.
    H. Comment: A few Customers believe that the purpose of the CRC is 
to market a hydro-only product, stating it is a change from the 
traditional rate method and departs from SHP allocations. They believe 
that the CRC also circumvents the rates process so that rates can be 
changed without a public rate process.
    Response: The CRC provides Western the ability to pay for the 
firming energy necessary to meet its contractual obligations while 
still maintaining an appropriate cash balance in the Basin Fund. Since 
Western is obligated to provide the contracted amount of energy, this 
is a firm product. Western will continue, as required by DOE 
regulations, to calculate a PRS each year to determine if the rates are 
sufficient to recover costs. If it is necessary to adjust the rate, 
Western will begin a rate process. All historical and future expenses 
will continue to be included in the PRS as in the past.
    I. Comment: A Customer stated that the CRC makes it appear as if 
there are sufficient funds to cover all costs.
    Response: In any year, the Basin Fund must have sufficient revenues 
to cover all costs. The CRC is developed to help ensure that a minimum 
balance is maintained and that the Basin Fund does not deplete rapidly. 
Western believes this is a positive step to help alleviate Basin Fund 
cash balance concerns.
    J. Comment: Some Customers asked Western to abandon the CRC and 
instead offer a contract to those Customers who want hydro only.
    Response: In order to offer a hydro only contract, Western would 
need to reopen the contracts and the Post-2004 Marketing Plan. These 
are not actions that are warranted at this time. Western will continue 
to market the SLCA/IP as described in the Post-2004 Marketing Plan. The 
CRC is designed to allow Customers some flexibility to choose if they 
want reduced energy deliveries rather than pay a higher cost for some 
of the firming expenses. The CRC helps maintain a certain minimum level 
in the Basin Fund and also protects the Basin

[[Page 47833]]

Fund from dramatic reductions in any given year. The CRC also assumes 
that the base rate is not affected by the Basin Fund balance. Western 
will continue to firm SHP as necessary. However, under certain 
financial hardship conditions, as determined by the CRC formulas, it 
may be necessary to implement the CRC to ensure sufficient revenue so 
that Western can meet its SHP obligation.
    K. Comment: A few Customers believe the WL can go below the HE if 
the costs are increased.
    Response: The WL will not be less than the HE. Western has 
corrected the CRC formula to prevent this from occurring.
    L. Comment: A Customer commented that implementation of the CRC 
must also include a complete review process so Customers have 
safeguards to ensure that cost recovery is limited only to the purpose 
for which the CRC was intended and that the CRC only be used in extreme 
circumstances.
    Response: Western believes safeguards are already in place under 
Attachment No. 5 to the SLCA/IP contracts because Customers can 
participate in the WPR process each year.
    M. Comment: A Customer commented that the CRC is not a fair method 
of creating a secure Basin Fund. It is particularly unfair to smaller 
Customers, because their limited alternative resources effectively 
eliminate the opportunity of opting out of the CRC.
    Response: Each Customer will be allowed to make its own choice to 
opt out of the CRC on a yearly basis. All Customers will continue to be 
given the opportunity to purchase WRP if they believe that the CRC is 
too expensive. Western believes it is to the Customer's advantage to 
have a lower base rate and an occasional CRC charge than to have a 
higher base rate all of the time.
    N. Comment: A Customer commented that it does not support the CRC 
and believes that Customers should not be required to pay a higher rate 
while relieving Western of its obligations to minimize other costs.
    Response: The CRC will only be implemented in years in which a 
financial hardship exists. Western will continue to consult with 
Customers about controlling costs in the WPR.
    O. Comment: A Customer commented that the CRC is a departure from 
historic practice. Rates have historically included purchase power 
costs.
    Response: Purchase power costs are still included in the firm power 
rate. The CRC is a new approach to deal with financial hardships that 
focuses on the Basin Fund Cash Balance. In the past, when financial 
hardships have occurred, Western has consulted with Customers on 
passing through firming costs or reducing energy deliveries. Western 
believes the CRC is a more certain method of dealing with financial 
hardships.
    P. Comment: A Customer commented that Western stated in its 
``Notice of Determination of the Post-2004 Marketable Resources'' that 
the yearly energy levels would be supported by necessary firming 
purchases in an appropriate firm power rate and energy allocations 
would only be changed by giving proper notice as set forth in the 
contract. The Customer believes the CRC circumvents this process.
    Responses: Firming purchases are included in the firm power rate, 
and the Customers' energy allocations will not change. The ability to 
obtain a waiver from the CRC will allow Customers to make their own 
decisions if they want to take their full SHP energy allocations or, if 
they would prefer, take less energy at a reduced rate.
    Q. Comment: A Customer commented that the CRC will not result in 
the lowest possible rate, consistent with sound business practices.
    Responses: Western believes the proposed firm power rate results in 
the lowest possible rate, consistent with sound business principles. 
The CRC will only be in place during financial hardship conditions. By 
adding the CRC only during these conditions, it will keep the rate 
lower during most years than if Western implemented a higher base rate.
    R. Comment: A commenter suggested Western abandon the CRC and 
instead develop a surcharge, with the amount fixed in advance of rate 
implementation that would be available for Western to implement in the 
event a Basin Fund shortfall was forecasted.
    Response: Western considers the CRC to be a superior option than a 
fixed surcharge. The CRC is variable in order to deal with the severity 
of the hardship and only charged during financial hardship conditions.
    S. Comment: Many Customers expressed support for the CRC.
    Response: Western appreciates the support it has received from the 
majority of Customers and believes that the CRC is a positive step to 
keep the Basin Fund solvent.
    T. Comment: A commenter supported the CRC, providing that each 
Customer is afforded a waiver opportunity.
    Response: Each May 1, all Customers will be notified if a CRC will 
be implemented and will be given the option to receive less energy in 
exchange for a waiver of the CRC for that year.
    U. Comment: Reclamation stated that the variable nature of the CRC 
diminishes the collaborative ratesetting processes between the two 
agencies. Furthermore, the CRC should not apply to power provided to 
Reclamation project loads. Because the project loads have priority in 
the use of Federal hydropower, these should not be affected by purchase 
power costs.
    Response: Western has no intention of changing the collaborative 
nature of the ratesetting process between the two agencies. Western 
looks forward to continuing to work with Reclamation on rate issues as 
it has done in the past and does not plan to change any of the 
processes in working with Reclamation, specifically the WPR. Western 
agrees that project loads should not be affected by purchase power 
costs and has agreed to not include Project Use loads in the CRC 
calculation.

Availability of Information

    Information about this rate adjustment, including power repayment 
studies, comments, letters, memorandums, and other supporting material 
made or kept by Western and used to develop the provisional rates, is 
available for public review in the Colorado River Storage Project 
Management Center, Western Area Power Administration, 150 East Social 
Hall Avenue, Suite 300, Salt Lake City, Utah.

Regulatory Procedure Requirements

Regulatory Flexibility Analysis

    The Regulatory Flexibility Act of 1980 (5 U.S.C. 601, et seq.) 
requires Federal agencies to perform a regulatory flexibility analysis 
if a final rule is likely to have a significant economic impact on a 
substantial number of small entities and there is a legal requirement 
to issue a general notice of proposed rulemaking. Western has 
determined that this action does not require a regulatory flexibility 
analysis since it is a rulemaking of particular applicability involving 
rates or services applicable to public property.

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.

[[Page 47834]]

Determination Under Executive Order 12866

    Western has an exemption from centralized regulatory review under 
Executive Order 12866; accordingly, no clearance of this notice by the 
Office of Management and Budget is required.

Small Business Regulatory Enforcement Fairness Act

    Western has determined that this rule is exempt from congressional 
notification requirements under 5 U.S.C. 801 because the action is a 
rulemaking of particular applicability relating to rates or services 
and involves matters of procedure.

Submission to the Federal Energy Regulatory Commission

    The interim rates herein confirmed, approved, and placed into 
effect, together with supporting documents, will be submitted to the 
Commission for confirmation and final approval.

Order

    In view of the foregoing and under the authority delegated to me, I 
confirm and approve on an interim basis, effective October 1, 2005, 
Rate Schedule SLIP-F8, for the Salt Lake City Area Integrated Projects 
of the Western Area Power Administration. The rate schedule shall 
remain in effect on an interim basis, pending the Commission's 
confirmation and approval of them or substitute rates on a final basis 
through September 30, 2010.

    Dated: August 1, 2005.
Clay Sell,
Deputy Secretary.

Salt Lake City Area Integrated Projects, Arizona, Colorado, Nevada, New 
Mexico, Utah, Wyoming; Schedule of Rates for Firm Power Service

    Effective: The first day of the first full billing period beginning 
on or after October 1, 2005, and extending through September 30, 2010, 
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 and Conditions of Service: Alternating current, 60 hertz, 
three-phase, delivered and metered at the voltages and points 
established by contract.
    Monthly Rate:
    Demand Charge: $4.43 per kilowatt of billing demand.
    Energy Charge: 10.43 mills per 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, and will be calculated as follows:

                             CRC Calculation
------------------------------------------------------------------------
                                 Description            Formula \1\
------------------------------------------------------------------------
     Step One--Determine the Net Balance Available in the Basin Fund
------------------------------------------------------------------------
                  BFBB....  Basin Fund Beginning   Financial forecast.
                             Balance ($).
BFTB......................  Basin Fund Target      .15 * PAE (not less
                             Balance ($).           than $20 million).
PAR.......................  Projected Annual       Financial forecast.
                             Revenue ($).
                            w/o CRC..............
PAE.......................  Projected Annual       Financial forecast.
                             Expense ($).
NR........................  Net Revenue ($)......  PAR-PAE.
NB........................  Net Balance ($)......  BFBB + NR.
---------------------------
       Step Two--Determine the Forecasted Energy Purchase Expenses
------------------------------------------------------------------------
EA........................  SHP Energy Allocation  Customer contracts.
                             (GWh).
HE........................  Forecasted Hydro       Hydrologic &
                             Energy (GWh).          generation forecast.
FE........................  Forecasted Energy      EA-HE.
                             Purchase (GWh).
FFC.......................  Forecasted Avg Energy  From commercially
                             Price per MWh($).      available price
                                                    indices.
FX........................  Forecasted Energy      FE * FFC.
                             Purchase Expense ($).
---------------------------
 Step Three--Determine the Amount of Funds Available for Firming Energy
  Purchases, and Then Determine Additional Revenue To Be Recovered. The
 Following Two Formulas Will Be Used To Determine FA, the Lesser of the
                            Two Will Be Used
------------------------------------------------------------------------
FA1.......................  Basin Fund Balance     If (NB>BFBB,FX,FX -
                             Factor ($).            (BFTB-NB)).
FA2.......................  Revenue Factor ($)...  If
                                                    (NR>.25*BFBB,FX,FX+N
                                                    R+.25*BFBB).
FA........................  Funds Available ($)..  Lesser of FA1 or FA2
                                                    (not less than $0).
FARR......................  Additional Revenue to  FX-FA.
                             be Recovered ($).
---------------------------
 Step Four--Once the FA for Purchases Have Been Determined, the CRC Can
               Be Calculated, and the WL Can Be Determined
------------------------------------------------------------------------
WL........................  Waiver Level (GWh)...  If
                                                    (EA 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 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 minus 25 percent of the Basin Fund 
Beginning Balance, then use the value for forecasted energy purchase 
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 Balance to the forecasted energy 
purchase 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 purchase 
power expenses.

FARR = FX-FA
Step Four: Once the additional revenue to be recovered has been 
determined, the Cost Recovery Charge (CRC) can be calculated, and the 
Waiver Level (WL) can be determined.
A. Cost Recovery Charge (CRC)
    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 (WL)
    The WL provides Customers the ability for Western to reduce 
purchase 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 + (FE * (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 
table below is the calculation of a PYA.

[[Page 47836]]



                             PYA CALCULATION
------------------------------------------------------------------------
                                 Description              Formula
------------------------------------------------------------------------
  Step One--Determine Actual Expenses and Purchases for Previous Year's
 Yirming. This Data Will be Obtained From Western's Financial Statements
                            at the End of FY
------------------------------------------------------------------------
PFX.......................  Prior Year Actual      Financial Statements.
                             Firming Expenses ($).
PFE.......................  Prior Year Actual      Financial Statements.
                             Firming Energy (GWh).
---------------------------
     Step Two--Determine the Actual Firming Cost for the CRC Portion
------------------------------------------------------------------------
EAC.......................  Sum of the energy      .....................
                             allocations of
                             Customers subject to
                             the PYA (GWh).
FFC.......................  Forecasted Firming     From CRC Calculation.
                             Energy Cost--($/MWh).
AFC.......................  Actual Firming Energy  PFX/PFE.
                             Cost--($/MWh).
CRCEP.....................  CRC Energy Percentage  From CRC Calculation.
CRCE......................  Purchased Energy for   EAC*CRCEP.
                             the CRC (GWh).
---------------------------
          Step Three--Determine Revenue Adjustment (RA) and PYA
------------------------------------------------------------------------
RA........................  Revenue Adjustment     (AFC-FFC)*CRCE*1,000.
                             ($).
PYA.......................  Prior Year Adjustment  (RA/EAC)/1,000.
                             (mills/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 end of 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 are 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 Customer 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 each 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).
    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 can choose not to take the full SHP energy supplied as 
determined in the attached formulas for 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 
measurement points between 95 percent lagging and 95 percent leading.
    Adjustment for Western Replacement Power:
    Under the Customer's Firm Electric Service Contract, as amended, 
Western will bill the Customer for its proportionate share of the costs 
of Western Replacement Power (WRP) within a given time period. Western 
will include in the Customer's monthly power bill the WRP cost and the 
incremental administrative costs associated with WRP.
    Adjustment for Customer Displacement Power Administrative Charges:
    Western will include in the Customer's regular monthly power bill 
the incremental administrative costs associated with CDP.

Certification of Rates

Colorado River Storage Project Management Center Salt Lake City Area 
Integrated Projects

    I certify that Rate Schedule SLIP-F8 developed for the Salt Lake 
City Area Integrated Projects is consistent with applicable laws and 
that the rates are the lowest possible consistent with sound business 
principles.

    Dated: July 5, 2005.
Michael S. Hacskaylo,
Administrator.
[FR Doc. 05-16044 Filed 8-12-05; 8:45 am]
BILLING CODE 6450-01-P