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

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URL: https://www.frixlaw.com/law-library/documents/fr%3A05-16044

## Record

- **Collection:** Federal Register
- **Document type:** Notice
- **Published:** August 15, 2005
- **Citation:** 70 FR 47823

## Text

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and places the rate schedules in effect on a final basis through September 30, 2010, or until the rate schedule is superseded.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
warren@wapa.gov
, 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
loftinc@wapa.gov
.

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The existing firm power Rate Schedule SLIP-F7 is being superseded by Rate Schedule SLIP-F8.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

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.

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

compares the current and proposed firm power rates:

Comparison of Current and Proposed Firm Power Rates

Current rate
Proposed 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 Balance ($)
$27,900,000
Financial forecast.

BFTB
Basin Fund Target Balance ($)
$27,665,550
$.15 * PAE (not less than $20 million).

PAR
Projected Annual Revenue ($) w/o CRC
$165,984,000
Financial forecast.

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 (GWh)
4,218
Hydrologic & generation forecast.

FE
Forecasted Energy Purchase (GWh)
427
EA−HE.

FFC
Forecasted Avg. Energy Price per MWh ($)
$55.50
From commercially available price indices.

FX
Forecasted Energy Purchase Expense ($)
$24,253,500
PE * 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 Leader of the Two Will Be Used

FA1
Based Fund Balance Factor ($)
$6,034,950
If (NB > BFBB, FX, FX− (BFTB−NB)).

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 Recovered ($)
$18,218,550
FX−FA.

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 Full SHP
93%
WL/EA*100.

CRCE
CRC Energy (GWh)
328
EA−WL.

CRCEP
CRC Energy Percentage of Full SHP
7%
CRCE/EA*100.

CRC
Cost Recovery Charge (mills/kWh)
3.91
FARR/(EA*1,000).

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

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 BFBB,FX,FX -(BFTB-NB)).

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

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

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

Step Four—Once the FA for Purchases 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.

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 Firming Expenses ($)
Financial Statements.

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

Step Two—Determine the Actual Firming Cost for the CRC Portion

EAC
Sum of the energy allocations of Customers subject to the PYA (GWh)

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

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

CRCEP
CRC Energy Percentage
From CRC Calculation.

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

Step Three—Determine Revenue Adjustment (RA) and PYA

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

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

Narrative PYA Calculation

Step One: Determine Actual Expenses and Purchases for Previous Year's Firming. This data will be obtained from Western's financial statements at 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

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A05-16044. Public record. Not legal advice.