Salt Lake City Area Integrated Projects-Rate Order No. WAPA-117, 47823-47836 [05-16044]
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Federal Register / Vol. 70, No. 156 / Monday, August 15, 2005 / Notices
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Docket Nos. ER05–1079–000, ER05–1079–
001, and ER05–1079–002]
Forest Investment Group, LLC; Notice
of Issuance of Order
August 8, 2005.
Forest Investment Group, LLC (Forest)
filed an application, as amended, for
market-based rate authority, with an
accompanying rate tariff. The proposed
rate tariff provides for the sales of
capacity and energy at market-based
rates. Forest also requested waiver of
various Commission regulations. In
particular, Forest requested that the
Commission grant blanket approval
under 18 CFR part 34 of all future
issuances of securities and assumptions
of liability by Forest.
On August 5, 2005, pursuant to
delegated authority, the Director,
Division of Tariffs and Market
Development—South, granted the
request for blanket approval under part
34. The Director’s order also stated that
the Commission would publish a
separate notice in the Federal Register
establishing a period of time for the
filing of protests. Accordingly, any
person desiring to be heard or to protest
the blanket approval of issuances of
securities or assumptions of liability by
Forest should file a motion to intervene
or protest with the Federal Energy
Regulatory Commission, 888 First
Street, NE., Washington, DC 20426, in
accordance with Rules 211 and 214 of
the Commission’s Rules of Practice and
Procedure. 18 CFR 385.211, 385.214
(2004).
Notice is hereby given that the
deadline for filing motions to intervene
or protest is September 6, 2005.
Absent a request to be heard in
opposition by the deadline above, Forest
is authorized to issue securities and
assume obligations or liabilities as a
guarantor, indorser, surety, or otherwise
in respect of any security of another
person; provided that such issuance or
assumption is for some lawful object
within the corporate purposes of Forest,
compatible with the public interest, and
is reasonably necessary or appropriate
for such purposes.
The Commission reserves the right to
require a further showing that neither
public nor private interests will be
adversely affected by continued
approval of Forest’s issuances of
securities or assumptions of liability.
Copies of the full text of the Director’s
Order are available from the
Commission’s Public Reference Room,
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888 First Street, NE., Washington, DC
20426. The Order may also be viewed
on the Commission’s Web site at
https://www.ferc.gov, using the eLibrary
link. Enter the docket number excluding
the last three digits in the docket
number filed to access the document.
Comments, protests, and interventions
may be filed electronically via the
internet in lieu of paper. See 18 CFR
385.2001(a)(1)(iii) and the instructions
on the Commission’s Web site under the
‘‘e-Filing’’ link. The Commission
strongly encourages electronic filings.
Linda Mitry,
Acting Secretary.
[FR Doc. E5–4402 Filed 8–12–05; 8:45 am]
BILLING CODE 6717–01–P
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Docket No. EL05–136–000]
Wisconsin Public Service Corporation;
Notice of Institution of Proceeding and
Refund Effective Date
August 8, 2005.
On August 4, 2005, the Commission
issued an order that instituted a
proceeding in Docket No. EL05–136–
000, pursuant to section 206 of the
Federal Power Act (FPA), 16 U.S.C.
824e, concerning the rate effect of
Wisconsin Public Service Corporation’s
deferred accounting treatment reflected
in its filing in Docket No. AC05–54–000.
Wisconsin Public Service Corporation,
112 FERC ¶ 61,165 (2005).
The refund effective date in Docket
No. EL05–136–000, established
pursuant to section 206(b) of the FPA,
will be 60 days from the date of
publication of this notice in the Federal
Register.
Linda Mitry,
Deputy Secretary.
[FR Doc. E5–4401 Filed 8–12–05; 8:45 am]
BILLING CODE 6717–01–P
DEPARTMENT OF ENERGY
Western Area Power Administration
Salt Lake City Area Integrated
Projects-Rate Order No. WAPA–117
Western Area Power
Administration, DOE.
ACTION: Notice of Order Concerning
Power Rates.
AGENCY:
SUMMARY: The Deputy Secretary of
Energy confirmed and approved Rate
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47823
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.
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.
DATES:
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.
FOR FURTHER INFORMATION CONTACT:
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
SUPPLEMENTARY INFORMATION:
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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
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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.
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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.
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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
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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.
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47825
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
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compares the current and proposed firm
power rates:
COMPARISON OF CURRENT AND PROPOSED FIRM POWER RATES
Current rate
Rate Schedule ...................................................................................................................................
Energy (mills/kWh) .............................................................................................................................
Capacity ($/kW month) ......................................................................................................................
Composite Rate (mills/kWh) ..............................................................................................................
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 $25
million per year, indexed for inflation.
This limitation is for CRC formula
calculation purposes only, and is not a
SLIP–F7
9.50
4.04
20.72
Proposed
rate
SLIP–F8
10.43
4.43
25.28
Increase
......................
.93
.39
4.56
cap on actual non-reimbursable
expenses.
Calculation of the CRC
Western will forecast the amount of
purchased energy necessary to deliver
SHP energy, the corresponding expense,
and determine the funds available for
firming purchases. In determining the
forecasted funds available, the impact
on Net Revenue (projected annual
revenue less projected annual
expenses), and the Basin Fund Net
Balance (Basin Fund FY beginning
balance plus net revenue) will be
analyzed. If the impact on both of these
fall short of the revenue and balance
triggers described above, the CRC will
not apply during that FY. If the impact
on either net revenue or the Basin Fund
balance is greater than the allowable
limits, the smaller factor will be used to
determine the additional revenue
requirements. For FY 2006, the CRC
charge is 0.0 mills/kWh. For purposes of
explaining how the CRC is calculated,
the following example is provided:
SAMPLE CRC CALCULATION
Formula 1
Description
Step One.—Determine the Net Balance Available in the Basin Fund
BFBB ................
BFTB .................
PAR ..................
PAE ...................
NR .....................
NB .....................
Basin Fund Beginning Balance ($)
Basin Fund Target Balance ($) ....
Projected Annual Revenue ($) w/o
CRC.
Projected Annual Expense ($) ......
Net Revenue ($) ...........................
Net Balance ($) .............................
$27,900,000
$27,665,550
$165,984,000
Financial forecast.
$.15 * PAE (not less than $20 million).
Financial forecast.
$184,437,000
$(18,453,000)
$9,447,000
Financial forecast.
PAR¥PAE.
BFBB + NR.
Step Two.—Determine the Forecasted Energy Purchase Expenses
EA .....................
HE .....................
FE .....................
FFC ...................
FX .....................
SHP Energy Allocation (GWh) ......
Forecasted Hydro Energy (GWh)
Forecasted
Energy
Purchase
(GWh).
Forecasted Avg. Energy Price per
MWh ($).
Forecasted Energy Purchase Expense ($).
4,655
4,218
427
$55.50
$24,253,500
Customer contracts.
Hydrologic & generation forecast.
EA¥HE.
From commercially available price indices.
PE * FFC.
Step Three.—Determine the Amount of Funds Available for Firming Energy Purchases, and Then Determine Additional Revenue To Be
Recovered. The Following Two Formulas Will Be Used To Determine FA, the Leader of the Two Will Be Used
FA1 ...................
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If (NB > BFBB, FX, FX¥ (BFTB¥NB)).
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47827
SAMPLE CRC CALCULATION—Continued
Formula 1
Description
FA2 ...................
FA .....................
FARR ................
Revenue Factor ($) .......................
Funds Available ($) .......................
Additional Revenue to be Recovered ($).
$12,775,500
$6,034,950
$18,218,550
If (NR > ¥.25*BFBB,FX, FX + NR +.25*BFBB).
Lesser of FA1 or FA2 (not less than $0).
FX¥FA.
Step Four.—Once the FA for Purchases Have Been Determined, the CRC Can Be Calculated, and the WL Can Be Determined
WL ....................
WLP ..................
CRCE ................
CRCEP .............
CRC ..................
1 Some
Waiver Level (GWh) .....................
Waiver Level Percentage of Full
SHP.
CRC Energy (GWh) ......................
CRC Energy Percentage of Full
SHP.
Cost Recovery Charge (mills/kWh)
4,327
93%
If (EA > HE, EA, HE + (FE*(FA/FX))), but not less than HE.
WL/EA*100.
328
7%
EA¥WL.
CRCE/EA*100.
3.91
FARR/(EA*1,000).
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
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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
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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)
($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
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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/
$24,253,500))
WL = 4,327 GWh
Prior Year Adjustment (PYA)
Calculation
Since the annual determination of the
CRC is based upon estimates, an annual
PYA will also be calculated when the
CRC is applied. The PYA will be
applied to those Customers who were
charged the CRC. The CRC PYA for
subsequent years will be determined by
comparing the prior year’s estimated
firming energy cost to the prior year’s
actual firming energy cost for the energy
provided above the WL. The PYA will
result in an increase or decrease to a
Customer’s firm energy costs over the
course of the following year. Because
there will not be a CRC for FY 2006, the
PYA will not be needed in 2007. Below
is an example of a PYA calculation.
SAMPLE PYA CALCULATION
Description
Formula
Step One—Determine Actual Expenses and Purchases for Previous Year’s Firming. This Data Will Be Obtained From Western’s
Financial Statements at the End of FY
PFX ...................
PFE ...................
Prior Year Actual Firming Expenses ($) ...................
Prior Year Actual Firming Energy (GWh) .................
$27,950,000
475
Financial Statements.
Financial Statements.
Step Two—Determine the Actual Firming Cost for the CRC Portion.
EAC ..................
FFC ...................
AFC ...................
CRCEP .............
CRCE ................
Sum of the energy allocations of Customers subject
to the PYA (GWh).
Forecasted Firming Energy Cost—($/MWh) ............
Actual Firming Energy Cost—($/MWh) ....................
CRC Energy Percentage ..........................................
Purchased Energy for the CRC (GWh) ....................
2,500
55.50
58.84
7%
176
From CRC Calculation.
PFX/PFE.
From CRC Calculation.
EAC*CRCEP.
Step Three—Determine Revenue Adjustment (RA) and PYA.
RA .....................
PYA ...................
Revenue Adjustment ($) ...........................................
Prior Year Adjustment (mills/kWh) ............................
$589,198
0.24
(AFC–FFC)*CRCE*1,000.
(RA/EAC)/1,000.
Narrative PYA Example Only (Assumes
That a CRC Was needed for the Previous
Year)
Step Two: Determine the actual firming
cost for the Cost Recovery Charge
portion.
AFC = (PFX / PFE) / 1,000
AFC = ($27,950,000 / 475) / 1,000
AFC = $58.84
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.
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
Step Three: Determine Revenue
Adjustment and PYA.
PFX—Prior year actual firming
expense,
PFX = $27,950,000
PFE—Prior year actual firming energy,
PFE = 475 GWh
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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
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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
Date each
year
Task
April 24—Month Study (Forecast to Model Projections).
CRC Notice to Customers .........
Waiver Request Submitted By
Customers.
Schedules Effective ...................
April 1.
May 1.
June 15.
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
Rate schedule
Current rate
October 1, 2003–
September 30,
2007
(SLIP–F7)
Proposed rate
October 1, 2005–
September 30,
2010
(SLIP–F8)
Percent
change
Energy (mills/kWh) ..........................................................................................................
CRC (if applicable) ..........................................................................................................
Total Energy Charge .......................................................................................................
Capacity ($/kWmonth) ....................................................................................................
9.5 ..........................
N/A .........................
9.5 ..........................
4.04 ........................
10.43 ......................
varies .....................
varies .....................
4.43 ........................
10
....................
N/A
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
($000)
Total Revenues ..........................................................................................................................
Proposed rate
($000)
Difference
($000)
$775,642
$815,494
$39,852
292,755
55,426
45,250
134,559
19,660
305,198
131,529
38,582
80,003
18,488
12,443
76,103
(6,668)
(54,556)
(1,172)
547,650
573,800
26,150
0
214,278
13,714
0
227,992
0
99,970
141,724
0
241,694
0
(114,308)
128,010
0
13,702
Revenue Distribution
Expenses:
O&M ....................................................................................................................................
Purchased Power and Wheeling ........................................................................................
Integrated Projects Requirements ......................................................................................
Interest ................................................................................................................................
Other ...................................................................................................................................
Total Expenses ............................................................................................................
Principal Payments:
Capitalized Expenses (deficits) ..........................................................................................
Original Project and Additions ............................................................................................
Replacements .....................................................................................................................
Irrigation ..............................................................................................................................
Total Principal Payments ............................................................................................
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Federal Register / Vol. 70, No. 156 / Monday, August 15, 2005 / Notices
SLCA/IP FIRM POWER COMPARISON OF 5-YEAR RATE PERIOD (FY 2006–FY 2010) TOTAL REVENUES AND EXPENSES—
Continued
Existing rate
($000)
Total Revenue Distribution ..........................................................................................
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
775,642
Acre—Feet ...................................................................................................................................
Percent .........................................................................................................................................
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
20,000
40%
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39,852
M&I
30,000
60%
Total
50,000
100%
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
Acre—Feet ...................................................................................................................................
Percent .........................................................................................................................................
815,494
Difference
($000)
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
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
Proposed rate
($000)
293,598
47.98%
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M&I
318,383
52.02%
Total
611,981
100%
Federal Register / Vol. 70, No. 156 / Monday, August 15, 2005 / Notices
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
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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
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47831
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-MonaNephi 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-MonaNephi 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 upto-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
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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-toirrigation 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
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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
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revised its formula to cap the nonreimbursable 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
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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
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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.
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47833
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.
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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, threephase, delivered and metered at the
voltages and points established by
contract.
Monthly Rate:
Demand Charge: $4.43 per kilowatt of
billing demand.
Energy Charge: 10.43 mills per
kilowatthour of use.
Cost Recovery Charge: This charge
will be recalculated annually before
May 1 and Western will provide
notification to the Customers. The
charge, if needed, will be placed into
effect from October 1 through
September 30, and will be calculated as
follows:
CRC CALCULATION
Formula 1
Description
Step One—Determine the Net Balance Available in the Basin Fund
BFBB ................
BFTB .................
PAR ..................
PAE ...................
NR .....................
NB .....................
Basin Fund Beginning Balance ($) ................................
Basin Fund Target Balance ($) .....................................
Projected Annual Revenue ($) ......................................
w/o CRC ........................................................................
Projected Annual Expense ($) .......................................
Net Revenue ($) ............................................................
Net Balance ($) ..............................................................
Financial forecast.
.15 * PAE (not less than $20 million).
Financial forecast.
Financial forecast.
PAR–PAE.
BFBB + NR.
Step Two—Determine the Forecasted Energy Purchase Expenses
EA .....................
HE .....................
FE .....................
FFC ...................
FX .....................
SHP Energy Allocation (GWh) ......................................
Forecasted Hydro Energy (GWh) ..................................
Forecasted Energy Purchase (GWh) ............................
Forecasted Avg Energy Price per MWh($) ...................
Forecasted Energy Purchase Expense ($) ...................
Customer contracts.
Hydrologic & generation forecast.
EA–HE.
From commercially available price indices.
FE * FFC.
Step Three—Determine the Amount of Funds Available for Firming Energy Purchases, and Then Determine Additional Revenue To Be
Recovered. The Following Two Formulas Will Be Used To Determine FA, the Lesser of the Two Will Be Used
FA1 ...................
FA2 ...................
FA .....................
FARR ................
Basin Fund Balance Factor ($) .....................................
Revenue Factor ($) ........................................................
Funds Available ($) ........................................................
Additional Revenue to be Recovered ($) ......................
If (NB>BFBB,FX,FX –(BFTB–NB)).
If (NR>.25*BFBB,FX,FX+NR+.25*BFBB).
Lesser of FA1 or FA2 (not less than $0).
FX–FA.
Step Four—Once the FA for Purchases Have Been Determined, the CRC Can Be Calculated, and the WL Can Be Determined
WL ....................
WLP ..................
CRCE ................
CRCEP .............
CRC ..................
1 Some
Waiver Level (GWh) ......................................................
Waiver Level Percentage of Full SHP ...........................
CRC Energy (GWh) .......................................................
CRC Energy Percentage of Full SHP ...........................
Cost Recovery Charge (mills/kWh) ...............................
If (EA<HE,EA,HE+(FE*(FA/FX))), but not less than HE.
WL/EA*100.
EA–WL.
CRCE/EA*100.
FARR/(EA*1,000).
formulas in this table are based on standard Excel spreadsheet formatting.
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Narrative of CRC Calculations
Step One: Determine the net balance
available in the Basin Fund.
BFBB—Western will forecast the
Basin Fund Beginning Balance for the
next FY.
BFTB—Determine the Basin Fund
Target Balance for the next FY. The
BFTB will not be less than $20 million.
The target balance is 15 percent of
projected annual expenses for the
coming FY.
BFTB = 0.15 * PAE
PAR—Projected Annual Revenue is
Western’s estimate of revenue for the
next FY.
PAE—Projected Annual Expense is
Western’s estimate of expenses for the
next FY. The PAE includes all expenses
plus 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 nonreimbursable expenses.
NR—Net Revenue equals revenues
minus expenses.
NR = PAR–PAE
NB—Net Balance is the Basin Fund
Beginning Balance plus net revenue.
NB = BFBB + NR
Step Two: Determine the forecasted
energy purchase expenses.
EA—The Sustainable Hydropower
Energy Allocation. This does not
include Project Use Customers.
HE—Western’s forecast of Hydro
Energy available during the next FY
developed from Reclamation’s April 24month study.
FE—Forecasted Energy purchases are
the difference between the sustainable
hydropower allocation and the
forecasted hydro energy available for the
next FY, or the anticipated firming
purchases for the next year.
FE = EA–HE
FFC—The forecasted energy price for
the next FY per MWh.
FX—Forecasted energy 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
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Step Three: Determine the amount of
Funds Available to spend on 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 use the value for
forecasted energy purchase power
expenses. 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)
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
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47835
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.
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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 ...................
PFE ...................
Prior Year Actual Firming Expenses ($) ...................................
Prior Year Actual Firming Energy (GWh) .................................
Financial Statements.
Financial Statements.
Step Two—Determine the Actual Firming Cost for the CRC Portion
EAC ...................
FFC ...................
AFC ...................
CRCEP ..............
CRCE ................
Sum of the energy allocations of Customers subject to the
PYA (GWh).
Forecasted Firming Energy Cost—($/MWh) ............................
Actual Firming Energy Cost—($/MWh) ....................................
CRC Energy Percentage ..........................................................
Purchased Energy for the CRC (GWh) ....................................
From CRC Calculation.
PFX/PFE.
From CRC Calculation.
EAC*CRCEP.
Step Three—Determine Revenue Adjustment (RA) and PYA
RA .....................
PYA ...................
Revenue Adjustment ($) ...........................................................
Prior Year Adjustment (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
VerDate jul<14>2003
14:41 Aug 12, 2005
Jkt 205001
(AFC–FFC)*CRCE*1,000.
(RA/EAC)/1,000.
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
PO 00000
Frm 00053
Fmt 4703
Sfmt 4703
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
ENVIRONMENTAL PROTECTION
AGENCY
[RCRA–2005–0013, FRL–7951–9]
Agency Information Collection
Activities: Proposed Collection;
Comment Request; Notification of
Regulated Waste Activity, EPA ICR
Number 0261.15, OMB Control Number
2050–0028
Environmental Protection
Agency.
ACTION: Notice.
AGENCY:
SUMMARY: In compliance with the
Paperwork Reduction Act (44 U.S.C.
3501 et seq.), this document announces
that EPA is planning to submit a
continuing Information Collection
Request (ICR) to the Office of
Management and Budget (OMB). This is
a request of an existing approved
collection. This ICR is scheduled to
E:\FR\FM\15AUN1.SGM
15AUN1
]]>Agencies
[Federal Register Volume 70, Number 156 (Monday, August 15, 2005)]
[Notices]
[Pages 47823-47836]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 05-16044]
-----------------------------------------------------------------------
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
[[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
