Pick-Sloan Missouri Basin Program-Eastern Division-Rate Order No. WAPA-140, 3022-3030 [E9-892]

Agencies

• DEPARTMENT OF ENERGY
• Western Area Power Administration

[Federal Register Volume 74, Number 11 (Friday, January 16, 2009)]
[Notices]
[Pages 3022-3030]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E9-892]


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DEPARTMENT OF ENERGY

Western Area Power Administration


Pick-Sloan Missouri Basin Program--Eastern Division-Rate Order 
No. WAPA-140

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of Order Concerning Firm Power Rates.

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SUMMARY: The Acting Deputy Secretary of Energy confirmed and approved 
Rate Order No. WAPA-140 and Rate Schedules P-SED-F10 and P-SED-FP10, 
placing firm power and firm peaking power rates from the Pick-Sloan 
Missouri Basin Program--Eastern Division (P-SMBP--ED) 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 (FERC) confirms, approves, and places them into 
effect on a final basis or until they are replaced by other rates. The 
provisional rates will provide sufficient revenue to pay all annual 
costs, including interest expense, and repayment of power investment 
and irrigation aid within the allowable periods.

DATES: Rate Schedules P-SED-F10 and P-SED-FP10 will be placed into 
effect on an interim basis on the first day of the first full billing 
period beginning on or after February 1, 2009, and will remain in 
effect until FERC confirms, approves, and places the rate schedules in 
effect on a final basis ending December 31, 2013, or until the rate 
schedules are superseded.

FOR FURTHER INFORMATION CONTACT: Mr. Robert J. Harris, Regional 
Manager, Upper Great Plains Region, Western Area Power Administration, 
2900 4th Avenue North, Billings, MT 59101-1266, telephone (406) 247-
7405, e-mail rharris@wapa.gov, or Ms. Linda Cady-Hoffman, Rates 
Manager, Upper Great Plains Region, Western Area Power Administration, 
2900 4th Avenue North, Billings, MT 59101-1266, (406) 247-7439, e-mail 
cady@wapa.gov.

SUPPLEMENTARY INFORMATION: The Deputy Secretary of Energy approved 
existing Rate Schedules P-SED-F9 and P-SED-FP9 for P-SMBP--ED firm and 
firm peaking electric service, respectively, on an interim basis on 
November 1, 2007 (72 FR 68,64,067 November 14, 2007), for a 5-year 
period beginning on January 1, 2008, and ending December 31, 2012.\1\
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    \1\ FERC confirmed and approved Rate Order No. WAPA-135 on April 
14, 2008, in Docket No. EF08-5031-000. See United States Department 
of Energy, Western Area Power Administration, Pick-Sloan Missouri 
Basin Program, 123 FERC ] 62048 (April 14, 2008).
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    Under Rate Schedule P-SED-F9, the composite rate is 24.49 mills per 
kilowatthour (mills/kWh), the firm energy rate is 13.99 mills/kWh, and 
the firm capacity rate is $5.65 per kilowattmonth (kWmonth). Under Rate 
Schedule P-SED-FP9, the firm peaking capacity rate is $5.10/kWmonth. 
These Rate Schedules are formula based with Base and Drought Adder 
components and provide for an up to 2 mills/kWh increase in the Drought 
Adder rate component.
    The current rate adjustment reflects a rate increase based on the 
P-SMBP Final Fiscal Year 2007 Power Repayment Study (PRS). The PRS sets 
the total annual P-SMBP--ED revenue requirement for 2009 for firm and 
firm peaking electric service at $283.0 million, or a 19.9 percent 
increase. The current rates, including the 2 mills/kWh increase 
provided for under the Drought Adder formula rate component, are not 
sufficient to meet the P-SMBP--ED revenue requirements.
    The P-SMBP--ED revenue requirement increase is mainly attributed to 
the economic impacts of the drought. A decrease in hydro-power 
generation has caused purchase power expense to increase and revenue 
from

[[Page 3023]]

non-firm energy sales to decrease. There has been an increase in both 
the price and volume of purchase power needed to meet contractual 
commitments to Western's customers. The purchase price of power is set 
by supply and demand on the open market.
    The existing firm electric service Rate Schedules P-SED-F9 and P-
SED-FP9 are being superseded by Rate Schedules P-SED-F10 and P-SED-
FP10, respectively. Under Rate Schedule P-SED-F10, the provisional 
rates for firm electric services will result in a combined composite 
rate of 29.34 mills/kWh. The energy rate will be 16.71 mills/kWh (a 
Base component of 9.27 mills/kWh and a Drought Adder component of 7.44 
mills/kWh), and the capacity rate will be $6.80/kWmonth (a Base 
component of $3.80/kWmonth and a Drought Adder component of $3.00/
kWmonth). Under Rate Schedule P-SED-FP10, the provisional rates for 
firm peaking electric services consist of a capacity charge of $6.20/
kWmonth (a Base component of $3.40/kWmonth and a Drought Adder 
component of $2.80/kWmonth) and an energy charge of 16.71 mills/kWh.
    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 the Administrator of Western; (2) the authority 
to confirm, approve, and place such rates into effect on an interim 
basis to the Deputy Secretary of Energy; and (3) the authority to 
confirm, approve, and place into effect on a final basis; to remand; or 
to disapprove such rates to FERC. Existing Department of Energy 
procedures for public participation in power rate adjustments (10 CFR 
part 903) were published on September 18, 1985.
    Under Delegation Order Nos. 00-037.00 and 00-001.00C, 10 CFR part 
903, and 18 CFR part 300, I hereby confirm, approve, and place Rate 
Order No. WAPA-140, the proposed P-SMBP--ED firm power, and firm 
peaking power rates into effect on an interim basis.
    The new Rate Schedules P-SED-F10 and P-SED-FP10 will be promptly 
submitted to FERC for confirmation and approval on a final basis.

    Dated: January 8, 2009.
Jeffrey F. Kupfer,
Acting Deputy Secretary.

Department of Energy

Deputy Secretary

In the matter of:

Western Area Power Administration Rate Adjustment for the Pick-Sloan 
Missouri Basin Program--Eastern Division; Rate Order No. WAPA-140;

Order Confirming, Approving, and Placing the Pick-Sloan Missouri Basin 
Program--Eastern Division Firm Power and Firm Peaking Power Service 
Rates Into Effect on an Interim Basis

    The firm and firm peaking electric service rates for the Pick-Sloan 
Missouri Basin Program--Eastern Division were established in accordance 
with section 302 of the Department of Energy (DOE) Organization Act (42 
U.S.C. 7152). This Act transferred to and vested in the Secretary of 
Energy the power marketing functions of the Secretary of the Department 
of the Interior and the Bureau of Reclamation 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 section 5 of the Flood Control Act 
of 1944 (16 U.S.C. 825s) 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 the Administrator of Western; (2) the authority 
to confirm, approve, and place such rates into effect on an interim 
basis to the Deputy Secretary of Energy; and (3) the authority to 
confirm, approve and place into effect on a final basis; to remand; or 
to disapprove such rates to the Federal Energy Regulatory Commission. 
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.
    Base: Revenue requirement component of the power rate including 
annual operation and maintenance expenses, investment repayment and 
associated interest, normal timing power purchases, and transmission 
costs.
    Capacity: The electric capability of a generator, transformer, 
transmission circuit, or other equipment. It is expressed in kilowatts.
    Capacity Charge: The rate which sets forth the charges for 
capacity. It is expressed in dollars per kilowattmonth.
    Composite Rate: The rate for commercial 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 per kilowatthour 
and used for comparison purposes.
    Corps: The United States Army Corps of Engineers.
    CROD: Contract Rate of Delivery. The maximum amount of capacity and 
energy allocated to a preference customer for a period specified under 
a contract.
    Customer: An entity with a contract that is receiving service from 
Western's Upper Great Plains Region.
    Deficits: Deferred or unrecovered annual and/or interest expenses.
    DOE: United States Department of Energy.
    DOE Order RA 6120.2: An order outlining power marketing 
administration financial reporting and rate-making procedures.
    Drought Adder: Formula-based revenue requirement component 
including costs associated with the drought.
    Energy: Measured in terms of the work it is capable of doing over a 
period of time. It is expressed in kilowatthours.
    Energy Charge: The rate which sets forth the charges for energy. It 
is expressed in mills per kilowatthour and applied to each kilowatthour 
delivered to each customer.
    FERC: Federal Energy Regulatory Commission.
    Firm: A type of product and/or service available at the time 
requested by the customer.
    FRN: Federal Register notice.
    Fry-Ark: Fryingpan-Arkansas Project.
    FY: Fiscal Year; October 1 to September 30.
    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.
    LAP: Loveland Area Projects.
    Load Factor: The ratio of average load in kW supplied during a 
designated period to the peak or maximum load in kW occurring in that 
period.
    mills/kWh: Mills per kilowatthour--the unit of charge for energy 
(equal to one tenth of a cent or one thousandth of a dollar).

[[Page 3024]]

    MISO: Midwest Independent Transmission System Operator.
    MW: Megawatt--the electrical unit of capacity that equals 1 million 
watts or 1,000 kilowatts.
    NEPA: National Environmental Policy Act of 1969 (42 U.S.C. 4321, et 
seq.).
    Non-timing Power Purchases: Power purchases that are not related to 
operational constraints such as management of endangered species, 
species habitat, water quality, navigation, control area purposes, etc.
    O&M: Operation and Maintenance.
    P-SMBP: The Pick-Sloan Missouri Basin Program.
    P-SMBP--ED: Pick-Sloan Missouri Basin Program--Eastern Division.
    P-SMBP--WD: Pick-Sloan Missouri Basin Program--Western Division.
    Power: Capacity and energy.
    Power Factor: The ratio of real to apparent power at any given 
point and time in an electrical circuit. Generally, it is expressed as 
a percentage.
    Preference: The provisions of Reclamation Law which require Western 
to first make Federal power available to certain entities. For example, 
section 9(c) of the Reclamation Project Act of 1939 (43 U.S.C. 485h(c)) 
states that preference in the sale of Federal power shall be given to 
municipalities and other public corporations or agencies and also to 
cooperatives and other nonprofit organizations financed in whole or in 
part by loans made under the Rural Electrification Act of 1936.
    Provisional Rate: A rate which has been confirmed, approved, and 
placed into effect on an interim basis by the Deputy Secretary.
    PRS: Power Repayment Study.
    Rate Brochure: An August 2008 document explaining the rationale and 
background for the rate proposal contained in this Rate Order.
    Reclamation: The 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, and deferred expenses) and repay Federal investments and 
other assigned costs.
    RMR: The Rocky Mountain Customer Service Region of the Western Area 
Power Administration.
    SPP: Southwest Power Pool.
    Timing Power Purchases: Power purchases that are due to operational 
constraints (e.g. management of endangered species, species habitat, 
water quality, navigation, control area purposes, etc.) and not 
associated with the drought.
    UGPR: The Upper Great Plains Customer Service Region of the Western 
Area Power Administration.
    Western: The United States Department of Energy, Western Area Power 
Administration.

Effective Date

    The new provisional rates will take effect on the first day of the 
first full billing period beginning on or after February 1, 2009, and 
will remain in effect until December 31, 2013, pending approval by FERC 
on a final basis.

Public Notice and Comment

    Western followed the Procedures for Public Participation in Power 
and Transmission Rate Adjustments and Extensions, 10 CFR part 903, in 
developing these rates. The steps Western took to involve interested 
parties in the rate process were:
    1. The proposed rate adjustment process began April 9, 2008, when 
Western's UGPR mailed a notice announcing informal customer meetings to 
all P-SMBP--ED preference customers and interested parties. The 
informal meetings were held on April 29, 2008, in Denver, Colorado, and 
on April 30, 2008, in Sioux Falls, South Dakota. At these informal 
meetings, Western explained the rationale for the rate adjustment, 
presented rate designs and methodologies, and answered questions.
    2. A Federal Register notice, published on August 15, 2008 (73 FR 
47945) announced the proposed rates for P-SMBP--ED, began a public 
consultation and comment period and announced the public information 
and public comment forums.
    3. On August 18, 2008, Western mailed letters to all P-SMBP--ED 
preference customers and interested parties transmitting the FRN 
published on August 15, 2008.
    4. On August 29, 2008, a letter was mailed to preference customers 
and interested parties informing them of a $400,000 misstatement in the 
FRN published revenue requirement.
    5. On September 9, 2008, at 9 a.m. (MDT), Western held a public 
information forum at the Ramada Plaza Hotel in Northglenn, Colorado. 
Western provided updates to the proposed firm power rates for the P-
SMBP, which encompasses the P-SMBP--ED and LAP rates. Western also 
answered questions and gave notice that more information was available 
in the rate brochure.
    6. On September 9, 2008, at 11:30 a.m. (MDT), following the public 
information forum, and at the same location, a public comment forum was 
held. The comment forum gave the public an opportunity to comment for 
the record. No oral or written comments were received at this forum.
    7. On September 10, 2008, at 8 a.m. (CDT), Western held a public 
information forum at the Holiday Inn in Sioux Falls, South Dakota. 
Western provided updates to the proposed firm power rates for the P-
SMBP, which encompasses the P-SMBP--ED and LAP rates. Western also 
answered questions and gave notice that more information was available 
in the rate brochure.
    8. On September 10, 2008, at 10:30 a.m. (CDT), following the public 
information forum, and at the same location, a public comment forum was 
held. The comment forum gave the public an opportunity to comment for 
the record. One oral comment was received at this forum.
    9. Western provided a Web site which contains all of the letters, 
time frames, dates, and locations of forums, documents discussed at the 
information meetings, FRNs, rate brochure, and all other information 
about this rate process for easy customer access. The Web site is 
located at https://www.wapa.gov/ugp/rates/2009FirmRateAdjust.
    10. During the consultation and comment period, which ended 
November 13, 2008, Western received 17 comment letters. One comment 
letter was rescinded. Western also received an oral comment. All 
formally submitted comments have been considered in preparing this Rate 
Order.

Comments

    Written comments were received from the following organizations:
    City of Blue Hill, Nebraska.
    City of Burwell, Nebraska (2).
    City of Fort Morgan, Colorado.
    City of Sargent, Nebraska.
    City of Wall Lake, Iowa.
    City of West Point, Nebraska.
    City of Wisner, Nebraska.
    City of Wood River, Nebraska.
    Corn Belt Power Cooperative, Iowa.
    Mid-West Electric Consumers Association, Colorado.
    North Iowa Municipal Electric Cooperative Association, Iowa.
    Spencer Municipal Utilities, Iowa.
    Village of Oxford, Nebraska.
    Village of Shickley, Nebraska.
    Village of Spencer, Nebraska.
    Village of Stuart, Nebraska.
    A representative of the following organization made an oral 
comment:
    Minnesota Municipal Utilities, Minnesota.

[[Page 3025]]

Project Description

    The P-SMBP was authorized by Congress in section 9 of the Flood 
Control Act of December 22, 1944, commonly referred to as the 1944 
Flood Control Act. This multipurpose program provides flood control, 
irrigation, navigation, recreation, preservation and enhancement of 
fish and wildlife, and power generation. Multipurpose projects have 
been developed on the Missouri River and its tributaries in Colorado, 
Montana, Nebraska, North Dakota, South Dakota, and Wyoming.
    In addition to the multipurpose water projects authorized by 
Section 9 of the Flood Control Act of 1944, certain other existing 
projects have been integrated with the P-SMBP for power marketing, 
operation, and repayment purposes. The Colorado-Big Thompson, Kendrick, 
and Shoshone Projects were combined with the P-SMBP in 1954, followed 
by the North Platte Project in 1959. These projects are referred to as 
the ``Integrated Projects'' of the P-SMBP.
    The Flood Control Act of 1944 also authorized the inclusion of the 
Fort Peck Project with the P-SMBP for operation and repayment purposes. 
The Riverton Project was integrated with the P-SMBP in 1954 and in 1970 
was reauthorized as a unit of P-SMBP.
    The P-SMBP is administered by two regions. The UGPR, with a 
regional office in Billings, Montana, markets power from the Eastern 
Division of P-SMBP, and the RMR, with a regional office in Loveland, 
Colorado, markets the Western Division power of P-SMBP. The UGPR 
markets power in western Iowa, western Minnesota, Montana east of the 
Continental Divide, North Dakota, South Dakota, and the eastern two-
thirds of Nebraska. The RMR markets P-SMBP--WD power, which in 
combination with Fry-Ark power is known as LAP power, in northeastern 
Colorado, east of the Continental Divide in Wyoming, west of the 101st 
meridian in Nebraska, and most of Kansas. The P-SMBP power is marketed 
to approximately 300 firm power customers by the UGPR and approximately 
60 firm power customers by the RMR.

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 P-SMBP. Repayment criteria are based on law, policies including DOE 
Order RA 6120.2, and authorizing legislation. To meet Cost Recovery 
Criteria outlined in DOE Order RA 6120.2, a revised study and rate 
adjustment has been developed to demonstrate that sufficient revenues 
will be collected under proposed rates to meet future obligations.

Existing and Provisional Rates

Eastern Division

    Under Rate Schedule P-SED-F9, the composite rate is 24.49 mills/
kWh, the firm energy rate is 13.99 mills/kWh, and the firm capacity 
rate is $5.65/kWmonth. For Rate Schedule P-SED-FP9 the firm peaking 
capacity rate is $5.10/kWmonth. These Rate Schedules are formula based 
with Base and Drought Adder components and provide for an up to a 2 
mills/kWh increase in the Drought Adder rate component.
    The current rate adjustment reflects a rate increase based on the 
P-SMBP Fiscal Year 2007 PRS. The PRS sets the total annual P-SMBP--ED 
revenue requirement for 2009 for firm and firm peaking electric service 
at $283.0 million, or a 19.9 percent increase.
    A comparison of the existing and provisional firm power and firm 
peaking power rates follow:

    Table 1--Comparison of Existing and Provisional Rates Pick-Sloan Missouri Basin Program--Eastern Division
----------------------------------------------------------------------------------------------------------------
            Firm electric service                 Current rates        Provisional rates       Percent change
----------------------------------------------------------------------------------------------------------------
Rate Schedules                                P-SED-F9/P-SED-FP9     P-SED-F10/P-SED-FP10
----------------------------------------------------------------------------------------------------------------
Firm and Firm Peaking Revenue Requirement                   $235.9                 $283.0                   19.9
 (million)..................................
Composite Rate (mills/kWh)..................                  24.49                  29.34                  19.8
Firm Capacity Rate (/kWmonth)...............                  $5.65                  $6.80                  20.4
Firm Energy Rate (mills/kWh)................                  13.99                  16.71                  19.4
Firm Peaking Capacity Rate (/kWmonth).......                  $5.10                  $6.20                  21.6
Firm Peaking Energy Rate (mills/kWh)\1\.....                  13.99                  16.71                 19.4
----------------------------------------------------------------------------------------------------------------
\1\ Firm Peaking Energy is normally returned. This rate will be assessed in the event Firm Peaking Energy is not
  returned.

Western Division

    The LAP rate is designed to recover the P-SMBP--WD revenue 
requirement for the P-SMBP and the revenue requirement for Fry-Ark. The 
adjustment to the LAP rate is a separate formal rate process which is 
documented in Rate Order No. WAPA-142. Rate Order No. WAPA-142 is 
scheduled to go into effect on the first day of the first full billing 
period after the Acting Deputy Secretary of Energy approves the rate.

Certification of Rates

    Western's Administrator certified that the Provisional Rates for P-
SMBP--ED firm power and firm peaking power rates are the lowest 
possible rates consistent with sound business principles. The 
Provisional Rates were developed following administrative policies and 
applicable laws.

P-SMBP--ED Firm Power Rate Discussion

    According to Reclamation Law, Western must establish power rates 
sufficient to recover operation, maintenance, purchased power and 
interest expenses, and repay power investment and irrigation aid.
    The P-SMBP--ED firm power and firm peaking power rates must be 
increased due to the economic impact of the drought, increased annual 
expenses, increased investments, and increased interest expense 
associated with deficits.
    Under Rate Schedule P-SED-F10, Western will continue identifying 
its firm electric service revenue requirement using Base and Drought 
Adder rate components. The Base rate component is a revenue requirement 
that includes annual operation and maintenance expenses, investment 
repayment and associated interest, normal timing power purchases, and 
transmission costs. Western's normal timing power purchases are 
purchases due to operational constraints (e.g., management of 
endangered species habitat, water quality, navigation, etc.) and are 
not associated with the current drought. The Base component cannot be

[[Page 3026]]

adjusted by Western without a public process.
    The Drought Adder rate component is a formula-based revenue 
requirement that includes costs attributable to the past and present 
drought conditions within the Pick-Sloan Program. The Drought Adder 
rate component includes costs associated with future non-timing power 
purchases to meet firm power contractual obligations not covered with 
available system generation due to the drought, previously incurred 
deficits due to purchased power debt that resulted from non-timing 
power purchases made during this drought, and the interest associated 
with the previously incurred and future drought deficit. The Drought 
Adder rate component is designed to repay Western's drought deficit 
within 10 years from the time the debt was incurred, using balloon-
payment methodology. For example, the drought deficit incurred by 
Western in 2007 will be repaid by 2017.
    The annual revenue requirement calculation will continue to be 
summarized by the following formula: Annual Revenue Requirement = Base 
Revenue Requirement + Drought Adder Revenue Requirement. Under this 
Provisional Rate, effective February 1, 2009, the P-SMBP--ED annual 
revenue requirement equals $294.1 million and is comprised of a Base 
revenue requirement of $163.5 million plus a Drought Adder revenue 
requirement of $130.6 million. Both the Base and Drought Adder rate 
components recover portions of the firm power revenue requirement, firm 
peaking power, and associated 5 percent discount revenue necessary to 
equal the P-SMBP--ED revenue requirement. A comparison of the current 
and proposed rate components are listed in Table 2.

                                 Table 2--Summary of P-SMBP--ED Rate Components
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                                      Existing rates P-SED-F9/P-SED-FP9     Provisional rates P-SED-F10/ P-SED-
                                   ---------------------------------------------------------FP10----------------
                                                   Drought                                Drought
                                        Base        adder        Total         Base        adder        Total
                                     component    component                 component    component
----------------------------------------------------------------------------------------------------------------
Firm Capacity Rate (/kWmonth).....        $3.65        $2.00        $5.65        $3.80        $3.00        $6.80
Firm Energy Rate (mills/kWh)......         8.93         5.06        13.99         9.27         7.44        16.71
Firm Peaking Capacity Rate (/             $3.25        $1.85        $5.10        $3.40        $2.80        $6.20
 kWmonth).........................
Firm Peaking Energy Rate (mills/           8.93         5.06        13.99         9.27         7.44       16.71
 kWh)\1\..........................
----------------------------------------------------------------------------------------------------------------
\1\ Firm peaking energy is normally returned. This will be assessed in the event firm peaking energy is not
  returned.

    As set forth in Table 2 above, provisional Rate Schedule P-SED-F10 
has a firm capacity rate of $6.80/kWmonth and a firm energy rate of 
16.71 mills/kWh. Under proposed Rate Schedule P-SED-FP10, the firm 
peaking capacity rate will increase to $6.20/kWmonth, or a 21.6 percent 
increase. Peaking energy is either returned to Western or paid for in 
accordance with the terms of the contract between Western and the 
peaking power customer.
    Continuing to identify the firm electric service revenue 
requirement using Base and Drought Adder rate components will assist 
Western in presenting the effects of the drought within the P-SMBP, 
demonstrating repayment of the drought related costs, and allowing 
Western to be more responsive to changes in drought related expenses. 
Western will continue to charge and bill customers firm electric 
service rates for energy and capacity, which are the sum of the Base 
and Drought Adder rate components.
    Western reviews its firm electric service rates annually. Western 
will review the Base rate component after the annual PRS is completed, 
generally in the first quarter of the calendar year. If an adjustment 
to the Base rate component is necessary, Western will initiate a public 
process pursuant to 10 CFR part 903 prior to making an adjustment.
    In accordance with the original implementation of the Drought Adder 
rate component, Western will continue to review the Drought Adder rate 
component each September to determine if drought costs differ from 
those projected in the PRS. If drought costs differ, Western will 
determine if an adjustment to the Drought Adder rate component is 
necessary. Western will notify customers by letter each October of the 
planned incremental or decremental adjustment and implement the 
adjustment in the January billing cycle. Although decremental 
adjustments to the Drought Adder rate component will occur as drought 
costs are repaid, the adjustments cannot result in a negative Drought 
Adder rate component. To give customers advance notice, Western will 
conduct a preliminary review of the Drought Adder rate component in 
early summer and notify customers by letter of the estimated change to 
the Drought Adder rate component for the following January. Western 
will verify the final Drought Adder rate component adjustment by 
notification in the October letter to the customers. Implementing the 
Drought Adder rate component adjustment on January 1 of each year will 
help keep the drought deficits from escalating as quickly, will lower 
the interest expense due to drought deficits, will demonstrate 
responsible deficit management, and will provide prompt drought deficit 
repayments.
    Western's current and Provisional Rate schedules provide for a 
formula-based adjustment of the Drought Adder rate component of up to 2 
mills/kWh. The 2 mills/kWh cap is intended to place a limit on the 
amount the Drought Adder formula can be adjusted relative to associated 
drought costs without initiating a public process to recover costs 
attributable to the Drought Adder formula rate for any one-year cycle.

Statement of Revenue and Related Expenses

    The following Table 3 provides a summary of projected revenue and 
expense data for the total P-SMBP, including both the Eastern and 
Western Divisions, firm electric service revenue requirement through 
the 5-year rate approval period.
    The firm power rates for both divisions have been developed with 
the following revenues and expenses for the P-SMBP:

[[Page 3027]]



  Table 3--Total P-SMBP Firm Power Comparison of 5-Year Rate Period (FY 2009-2013) Total Revenues and Expenses
----------------------------------------------------------------------------------------------------------------
                                                                   Current rate     Provisional     Difference
                                                                      ($000)       rate  ($000)       ($000)
----------------------------------------------------------------------------------------------------------------
Total Revenues..................................................       2,124,002       2,417,497         293,495
Revenue Distribution
Expenses:
    O&M.........................................................         904,589         859,559        (45,030)
    Purchased Power.............................................         155,654         431,180         275,526
    Interest....................................................         528,272         639,356         111,084
    Transmission................................................          55,596          65,963          10,367
                                                                 -----------------------------------------------
        Total Expenses..........................................       1,644,111       1,996,058         351,947
                                                                 -----------------------------------------------
Principal Payments:
    Capitalized Expenses (Deficits)\1\..........................         150,549         351,517         200,968
    Original Project and Additions\1\...........................         263,052           1,546       (261,506)
    Replacements\1\.............................................           3,314           2,704           (610)
    Irrigation Aid..............................................          62,976          65,672           2,696
                                                                 -----------------------------------------------
        Total Principal Payments................................         479,891         421,439        (58,452)
                                                                 -----------------------------------------------
            Total Revenue Distribution..........................       2,124,002       2,417,497        293,495
----------------------------------------------------------------------------------------------------------------
\1\ Due to the deficit or near deficit conditions between 1999 and 2008, revenues generated in the cost
  evaluation period are applied toward repayment of deficits rather than repayment of project additions and
  replacements. All deficits are projected to be repaid by 2017.

Basis for Rate Development

    The existing rates for P-SMBP--ED firm power in Rate Schedule P-
SED-F9, which expire December 31, 2012, no longer provide sufficient 
revenues to pay all annual costs, including interest expense, and repay 
investment and irrigation aid within the allowable period. The adjusted 
rates reflect increases due to the economic impact of the drought, 
increased annual expenses, increased investments, and increased 
interest expense associated with investments and drought deficits. The 
Provisional Rates will provide sufficient revenue to pay all annual 
costs, including interest expense, and repay power investment and 
irrigation aid within the allowable periods. The Provisional Rates will 
take effect on February 1, 2009, and will remain in effect on an 
interim basis, pending FERC's confirmation and approval of them or 
substitute rates on a final basis, through December 31, 2013.

Emergency Fund Discussion

    Due to continuing below-normal hydropower generation, Western may 
need to use the Continuing Fund (Emergency Fund) to pay for 
unanticipated purchase power and wheeling expenses necessary to meet 
its contractual obligations for the sale and delivery of power to its 
customers. Should Western use this funding mechanism, Western will 
replenish the Continuing Fund (Emergency Fund) in accordance with law 
and Western's current repayment policy.\2\
---------------------------------------------------------------------------

    \2\ Western's Continuing Fund (Emergency Fund) Policy can be 
found at https://www.wapa.gov/powerm/pdf/repaypolicy.pdf.
---------------------------------------------------------------------------

Comments

    The comments and responses below regarding the firm and firm 
peaking electric service rates are paraphrased for brevity when not 
affecting the meaning of the statement(s). Direct quotes from comment 
letters are used for clarification when necessary.
    The issues discussed are (1) Firm Power Rate and (2) MISO Markets.
1. Firm Power Rate
    Comment: Western received numerous comments from customers stating 
that they understand the need for the rate increases and support the 
concept of the Drought Adder, which provides a set window during which 
drought-related expenses are repaid.
    Response: Western appreciates the customer support received for the 
rate adjustment proposal. Western continues separation of the annual 
revenue requirement into Base and Drought Adder components.
    Comment: Many comments were received from customers that showed 
appreciation for Western's commitment to keep power customers informed 
and involved throughout this rate process. Customers were grateful for 
past cost-cutting measures and encouraged Western's continued vigilance 
in keeping controllable costs as low as possible.
    Response: Western is pleased with the level of customer interest 
and participation in the public meetings. Under the Flood Control Act 
of 1944, power is to be sold at the lowest possible rates consistent 
with sound business principles. Western is committed to keeping 
controllable costs as low as possible while continuing to deliver 
reliable cost-based hydroelectric power and related services.
    Comment: Customers state that they are looking forward to working 
with Western's staff on the projected Base rate adjustments as they 
pertain to Western's draft Strategic Plan and Western's potential 
involvement in changes associated with MISO and SPP.
    Response: Western's goal is to work closely with our customers 
throughout this rate, as well as any future rate adjustments. Changes 
to the Base Rate are made through a public process and allow for input.
    Comment: Two customers were opposed to the firm peaking rate and 
questioned whether it reflects the costs associated with the drought 
and delivery of peaking power. It was noted that the firm peaking rate 
is being increased at approximately the same percentage rate as the 
firm power rate, which the commenting customers felt may not be fair 
and equitable. These customers wanted additional information regarding 
the firm peaking contracts so the impact on the rates can be better 
understood and evaluated. It was understood that Western allows peaking 
energy to be returned. They questioned under what terms and

[[Page 3028]]

conditions peaking customers are allowed to return energy and whether 
peaking energy is allowed to be returned off-peak. Customers asked if 
Western makes market purchases to fulfill Western's peaking contracts. 
The customers asked for assurance from Western that the firm peaking 
rate is fairly priced based on the nature of the product and its 
historical and future contributions to the bottom line.
    Response: Western separated the firm and firm peaking rates and 
developed rate designs for both firm power and firm peaking power in 
the FRN published November 14, 2007 (72 FR ] 64067). In development of 
this firm peaking rate design, Western analyzed historical peaking data 
and concluded that this rate reflects the firm peaking customer's 
historical usage and their impact on the drought costs. During the 
current rate adjustment process, Western concluded that there has not 
been substantial change to the firm peaking usage or power markets 
since the introduction of the new firm peaking rate design that would 
support revisiting the rate design at this time. Western believes that 
both the firm and firm peaking customers are being treated equitably 
with the current rate designs. The firm peaking rate design accurately 
reflects the value and restrictions of the peaking product.
    Comment: One customer would like to evaluate the voltage discount 
and was concerned that it may be too high in light of the recent 
drought-related increases. The concern was that billing amounts have 
grown since the voltage discount was put into place and now the 
discount may be too much in comparison to the actual cost.
    Response: Historically, Western has provided a 5-percent voltage 
discount as a provision to the firm power rate schedule. The purpose of 
the discount is to provide the discount on firm power sales to 
customers who receive deliveries at higher transmission voltage and 
relieve Western of substation delivery costs. Reclamation began, and 
Western continues, the 5-percent voltage discount to customers meeting 
the criteria. Up to this time, Western has not been formally asked to 
change the discount percentage and has not evaluated the impacts of 
such a change on the firm power customers. Western is open to 
discussion among our customers and exploring options regarding the 5-
percent voltage discount; but until additional customers request a 
review or modification of this provision, Western will continue 
applying the discount.
    Comment: One customer recognized the impacts that the extended 
drought has had on the current financial status of the P-SMBP and 
expressed support for the proposed firm power rate increases. The 
customer also stated that the repayment of Federal investment through 
Federal power rates is taken very seriously. In the future, the Drought 
Adder will help to avoid a repetition of the financial impacts that are 
seen today.
    Response: Western acknowledges the extended drought, its financial 
impacts, and the need for a firm power rate increase as well. The 
Drought Adder will allow Western to be more responsive to the changing 
hydrological conditions.
    Comment: A customer representative acknowledged the financial 
challenges of this drought and made note of the difficulties Federal 
power customers are confronted with in fulfilling their financial 
responsibilities to the Federal government. They noted the good water 
years in the 1990s generated significant revenue surplus to P-SMBP 
financial requirements. Also noted was Western's administration of 
repayment according to repayment policies and the repayment of a 
significant amount of capital investment ahead of schedule. This early 
repayment benefitted both P-SMBP customers and the Federal government 
but left no financial resources to deal with drought. Thus, the current 
repayment practices and policies exacerbate the impacts of the natural 
swings in hydrology. When the drought deficit is repaid, there will 
still be a substantial amount of paid-ahead investments for the P-SMBP. 
The customer would like to work with Western to address this issue.
    Response: Western acknowledges the financial impacts of the current 
drought and believes the ratemaking policy of identifying the Base and 
Drought Adder components will make the rates more responsive to 
hydrological changes caused by both drought and flush water years. The 
Drought Adder component may be adjusted annually up to 2 mills/kWh 
without a public process to quickly address drought impacts, and the 
Base Rate component can only be adjusted through a public process. This 
practice will lower interest expense due to drought deficits and 
demonstrate responsible deficit management. Western acknowledges the 
customer group statements regarding Western's adherence to repayment 
policies and the associated repayment of a significant amount of 
capital investment ahead of schedule in the 1990s. Prepayment is an 
integral part of the long-term plan for P-SMBP and has provided rate 
stability for consumers while meeting Federal repayment obligations. 
The ability to reduce the Drought Adder rate component when normal 
hydrological conditions return to P-SMBP will allow appropriate 
recognition of repayment obligations. Western appreciates the 
customers' support and willingness to work with Western and will 
continue to discuss issues, impacts, and possible solutions with the 
customers.
2. MISO Markets
    Comment: Western has received numerous comments concerning the 
issue of whether to join MISO and its Day Two Markets. The comments 
support a thorough review of costs and benefits to all of Western's 
customers before a change is made. Comments suggest that administrative 
costs associated with the Day Two Markets may impose a significant 
burden, especially on smaller customers. There were concerns that if 
Western joins MISO and other area transmission owners that serve the 
customers join SPP there could be significant cost issues associated 
with the delivery of Western's allocation to Preference customer loads. 
Comments stated that if there are benefits to participating in the Day 
Two Market those benefits should flow to all of Western's customers, 
not just those that participate in joint dispatching arrangements 
inside the Integrated System. Concerns are that costs associated to 
deliver Western's allocations to the edge of the system should be 
recovered as part of the total system transmission rate recovery, as it 
has been done in the past.
    Response: This comment is not directly related to the proposed rate 
action. However, Western is actively addressing these issues as well as 
other options and evaluating them based on costs and benefits to 
Western's customers.
    Comment: A commenter noted that MISO intends to start an ancillary 
service market; and when that occurs, Western has preference power 
customers that are served in the MISO footprint. The question was asked 
does Western have avoided costs due to the MISO market providing those 
ancillary services; specifically, are there avoided costs in Schedule 
3, Regulation and Frequency Response; Schedule 5, Operating Reserves 
Spinning; and Schedule 6, Operating Reserves Supplemental.
    Response: This comment is not directly related to the proposed rate 
action. Western is actively evaluating its obligations to customers in 
the MISO Ancillary Services Market footprint. As Western moves forward 
in evaluating the impacts on market participation and changes for 
customers, Western will

[[Page 3029]]

seek input from customers and will continue to keep customers informed 
of decisions regarding these matters.

Availability of Information

    Information about this rate adjustment, including the PRS, 
comments, letters, memorandums, and other supporting materials that was 
used to develop the Provisional Rates is available for public review in 
the Upper Great Plains Regional Office, Western Area Power 
Administration, 2900 4th Avenue North, Billings, Montana.

Ratemaking Procedure Requirements

Environmental Compliance

    In compliance with the National Environmental Policy Act (NEPA) of 
1969, 42 U.S.C. 4321-4347; 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 of an environmental assessment or an environmental impact 
statement.

Determination Under Executive Order 12866

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

Submission to the Federal Energy Regulatory Commission

    The Provisional Rates herein confirmed, approved, and placed into 
effect, together with supporting documents, will be submitted to FERC 
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 February 1, 2009, 
Rate Schedules P-SED-F10 and P-SED-FP10 for the Pick-Sloan Missouri 
Basin Program--Eastern Division Project of the Western Area Power 
Administration. These rate schedules shall remain in effect on an 
interim basis, pending FERC's confirmation and approval of them or 
substitute rates on a final basis through December 31, 2013.

    Dated: January 8, 2009.
Jeffrey F. Kupfer,
Acting Deputy Secretary.

Rate Schedule P-SED-F10
(Supersedes Schedule P-SED-F9)
Effective February 1, 2009

United States Department of Energy, Western Area Power Administration

Pick-Sloan Missouri Basin Program--Eastern Division Montana, North 
Dakota, South Dakota, Minnesota, Iowa, Nebraska

Schedule of Rates for Firm Power Service

(Approved Under Rate Order No. WAPA-140)

    Effective: The first day of the first full billing period beginning 
on or after February 1, 2009, through December 31, 2013.
    Available: Within the marketing area served by the Eastern Division 
of the Pick-Sloan Missouri Basin Program.
    Applicable: To the power and energy delivered to customers as firm 
power service.
    Character: Alternating current, 60 hertz, three phase, delivered 
and metered at the voltages and points established by contract.

Monthly Rates

    Demand Charge: $6.80 for each kilowatt per month (kWmonth) of 
billing demand.
    Energy Charge: 16.71 mills per kilowatthour (kWh) for all energy 
delivered as firm power service.
    Billing Demand: The billing demand will be as defined by the power 
sales contract.

Charge Components

    Base: A fixed revenue requirement that includes operation and 
maintenance expense, investments and replacements, interest on 
investments and replacements, normal timing purchase power costs 
(purchases due to operational constraints, not associated with 
drought), and transmission costs. The Base revenue requirement is 
$163.5 million.
[GRAPHIC] [TIFF OMITTED] TN16JA09.008

    Drought Adder: A formula-based revenue requirement that includes 
future purchase power expense excluding timing purchases, previous 
purchase power drought deficits, and interest on the purchase power 
drought deficits. For the period beginning February 1, 2009, the 
Drought Adder revenue requirement is $130.6 million.
[GRAPHIC] [TIFF OMITTED] TN16JA09.009

    Process: Any proposed change to the Base component will require a 
public process. The Drought Adder component may be adjusted annually 
using the above formula for any costs attributed to drought of less 
than or equal to the equivalent of 2 mills/kWh to the Power Repayment 
Study (PRS) composite rate. Any planned incremental adjustment to the 
Drought Adder component greater than the equivalent of 2 mills/kWh to 
the PRS composite rate will require a public process.

Adjustments

    For Drought Adder: Adjustments pursuant to the Drought Adder

[[Page 3030]]

component will be documented in a revision to this rate schedule.
    For Character and Conditions of Service: Customers who receive 
deliveries at transmission voltage may in some instances be eligible to 
receive a 5-percent discount on demand and energy charges when 
facilities are provided by the customer that results in a sufficient 
savings to Western to justify the discount. The determination of 
eligibility for receipt of the voltage discount shall be exclusively 
vested in Western.
    For Billing of Unauthorized Overruns: For each billing period in 
which there is a contract violation involving an unauthorized overrun 
of the contractual firm power and/or energy obligations, such overrun 
shall be billed at 10 times the above rate.
    For Power Factor: None. The customer will be required to maintain a 
power factor at the point of delivery between 95 percent lagging and 95 
percent leading.
Rate Schedule P-SED-FP10
(Supersedes Schedule P-SED-FP9)
Effective February 1, 2009

United States Department of Energy, Western Area Power Administration

Pick-Sloan Missouri Basin Program--Eastern Division Montana, North 
Dakota, South Dakota, Minnesota, Iowa, Nebraska;

Schedule of Rates for Firm Peaking Power Service

(Approved Under Rate Order No. WAPA-140)

    Effective: The first day of the first full billing period beginning 
on or after February 1, 2009, through December 31, 2013.
    Available: Within the marketing area served by the Eastern Division 
of the Pick-Sloan Missouri Basin Program, to customers with generating 
resources enabling them to use firm peaking power service.
    Applicable: To the power sold to customers as firm peaking power 
service.
    Character: Alternating current, 60 hertz, three phase, delivered 
and metered at the voltages and points established by contract.

Monthly Rates

    Demand Charge: $6.20 for each kilowatt per month (kWmonth) of the 
effective contract rate of delivery for peaking power or the maximum 
amount scheduled, whichever is greater.
    Energy Charge: 16.71 mills for each kilowatthour (kWh) for all 
energy scheduled for delivery without return.

Charge Components

    Base: A fixed revenue requirement that includes operation and 
maintenance expense, investment and replacements, normal timing 
purchase power costs (purchases due to operational constraints, not 
associated with drought), and transmission costs. The Base peaking 
revenue requirement is $14.5 million.
[GRAPHIC] [TIFF OMITTED] TN16JA09.010

    Energy \1\ = 9.27 mills/kWh
    Drought Adder: A formula-based revenue requirement that includes 
future purchase power above timing purchases, previous purchase power 
drought deficits, and interest on the purchase power drought deficits. 
For the period beginning February 1, 2009, the Drought Adder peaking 
revenue requirement is $12.0 million.
[GRAPHIC] [TIFF OMITTED] TN16JA09.011

Energy \1\ = 7.44 mills/kWh
---------------------------------------------------------------------------

    \1\ Firm peaking energy is normally returned. This rate will be 
assessed in the event firm peaking energy is not returned.
---------------------------------------------------------------------------

    Process:
    Any proposed change to the Base component will require a public 
process. The Drought Adder component may be adjusted annually using the 
above formula for any costs attributed to drought of less than or equal 
to the equivalent of 2 mills/kWh to the Power Repayment Study (PRS) 
composite rate. Any planned incremental adjustment to the Drought Adder 
component greater than the equivalent of 2 mills/kWh to the PRS 
composite rate will require a public process.
    Billing Demand: The billing demand will be the greater of: (1) The 
highest 30-minute integrated demand measured during the month up to, 
but not in excess of, the delivery obligation under the power sales 
contract, or (2) the contract rate of delivery.

Adjustments

    For Drought Adder: Adjustments pursuant to the Drought Adder 
component will be documented in a revision to this rate schedule.
    Billing for Unauthorized Overruns: For each billing period in which 
there is a contract violation involving an unauthorized overrun of the 
contractual obligation for peaking demand and/or energy, such overrun 
shall be billed at 10 times the above rate.

 [FR Doc. E9-892 Filed 1-15-09; 8:45 am]
BILLING CODE 6450-01-P