Pick-Sloan Missouri Basin Program-Eastern Division-Rate Order No. WAPA-126, 71280-71288 [E5-6576]

Agencies

• DEPARTMENT OF ENERGY
• Western Area Power Administration

[Federal Register Volume 70, Number 227 (Monday, November 28, 2005)]
[Notices]
[Pages 71280-71288]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E5-6576]


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DEPARTMENT OF ENERGY

Western Area Power Administration


Pick-Sloan Missouri Basin Program--Eastern Division--Rate Order 
No. WAPA-126

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of order concerning power rates.

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SUMMARY: The Deputy Secretary of Energy confirmed and approved Rate 
Order No. WAPA-126 and Rate Schedules P-SED-F8 and P-SED-FP8, 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 (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 repay power investment and 
irrigation aid, within the allowable periods.

DATES: Rate Schedules P-SED-F8 and P-SED-FP8 will be placed into effect 
on an interim basis on the first day of the first full billing period 
beginning on or after January 1, 2006, and will be in effect until the 
Commission confirms, approves, and places the rate schedules in effect 
on a final basis ending December 31, 2010, 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are superseded.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-

[[Page 71281]]

1266, telephone (406) 247-7405, e-mail rharris@wapa.gov, or Mr. Jon R. 
Horst, Rates Manager, Upper Great Plains Region, Western Area Power 
Administration, 2900 4th Avenue North, Billings, MT 59101-1266, 
telephone (406) 247-7444, e-mail horst@wapa.gov.

SUPPLEMENTARY INFORMATION: The Deputy Secretary of Energy approved 
existing Rate Schedules P-SED-F7 and P-SED-FP7 for P-SMBP--ED firm 
power service and firm peaking power service on December 24, 2003 (Rate 
Order No. WAPA-110, 69 FR 649, January 6, 2004). The Commission 
confirmed and approved the rate schedules on December 23, 2004, in FERC 
Docket No. EF04-5031-000 (109 FERC 62,234). The existing rate schedules 
are effective from February 1, 2004, through December 31, 2008.
    The P-SMBP--ED firm power and firm peaking power rates must be 
increased due to the economic impact of the drought, increased 
operation and maintenance and other annual expenses, increased 
investments, and increased interest expense associated with deficits. 
The studies have also been adjusted to account for calendar year 
implementation versus a fiscal year implementation.
    The existing firm power Rate Schedule is being superseded by Rate 
Schedule P-SED-F8. Under Rate Schedule P-SED-F7, the energy charge is 
9.62 mills per kilowatthour (mills/kWh), and the capacity charge is 
$3.72 per kilowattmonth (kWmonth). The composite rate is 16.51 mills/
kWh. The provisional rates for P-SMBP--ED firm power are being 
implemented in two steps. The first step of the provisional firm power 
rates consists of an energy charge of 10.69 mills/kWh and a capacity 
charge of $4.20 per kWmonth. The first step of the provisional rates 
for P-SMBP--ED firm power in Rate Schedule P-SED-F8 will result in an 
overall composite rate of 18.47 mills/kWh on January 1, 2006, and will 
result in an increase of about 11.9 percent when compared with the 
existing P-SMBP--ED firm power rates under Rate Schedule P-SED-F7. The 
second step of the provisional firm power rates consists of an energy 
charge of 11.29 mills/kWh and a capacity charge of $4.45 per kWmonth. 
The second step of the provisional rates for P-SMBP--ED firm power in 
Rate Schedule P-SED-F8 will result in an overall composite rate of 
19.54 mills/kWh on January 1, 2007, and will result in an increase of 
about 5.8 percent, with a total compounded increase after both steps of 
about 18.4 percent.
    The existing firm peaking power Rate Schedule is being superseded 
by Rate Schedule P-SED-FP8. Under Rate Schedule P-SED-FP7, the firm 
peaking energy charge is 9.62 mills/kWh, and the firm peaking capacity 
charge is $3.72 per kWmonth. The first step of the provisional rates 
consists of an energy charge of 10.69 mills/kWh and a capacity charge 
of $4.20 per kWmonth on January 1, 2006. The second step of the 
provisional rates consists of an energy charge of 11.29 mills/kWh and a 
capacity charge of $4.45 per kWmonth on January 1, 2007.
    The new rates will be higher than the existing rates, primarily due 
to increased purchased power and deferred annual expenses (deficits) 
associated with extended drought conditions. The proposed increase is 
more than 18 percent, which, combined with the recent rate increase in 
2004, will result in a total increase in excess of 37 percent by 2007.
    Incorporating these costs in the current Power Repayment Study 
confirms that existing rates do not provide enough revenue to repay 
irrigation assistance for Bureau of Reclamation Projects in future 
years. 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 to meet future obligations.
    The proposed rates will provide sufficient revenue to pay all 
annual costs, including interest expense, and meet required investment 
repayment within the allowable periods outlined in DOE Order RA 6120.2 
and applicable legislation. Implementing the increase in two steps 
helps mitigate the financial impact of a single larger rate adjustment.
    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-126, the proposed P-SMBP--ED firm power, and firm 
peaking power rates into effect on an interim basis. The new Rate 
Schedules P-SED-F8 and P-SED-FP8 will be promptly submitted to the 
Commission for confirmation and approval on a final basis.

    Dated: November 9, 2005.
Clay Sell,
Deputy Secretary.

Department of Energy, Deputy Secretary

In the Matter of: Western Area Power Administration; Rate Adjustment; 
Pick-Sloan Missouri Basin Program--Eastern Division

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
    These rates were established in accordance with section 302 of the 
Department of Energy (DOE) Organization Act (42 U.S.C. 7152). This Act 
transferred to and vested in the Secretary of Energy the power 
marketing functions of the Secretary of the Department of the Interior 
and the Bureau of Reclamation 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.
    Capacity: The electric capability of a generator, transformer, 
transmission circuit, or other equipment. It is expressed in kW.
    Capacity Charge: The rate which sets forth the charges for 
capacity. It is expressed in $ per kWmonth.

[[Page 71282]]

    Commission: Federal Energy Regulatory Commission.
    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/kWh and used for 
comparison purposes.
    Corps: United States Army Corps of Engineers.
    CROD: Contract rate of delivery. The maximum amount of capacity 
made available 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 expenses.
    DOE: United States Department of Energy.
    DOE Order RA 6120.2: An order outlining with power marketing 
administration financial reporting and ratemaking procedures.
    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 
killowatthour delivered to each customer.
    FERC: Federal Energy Regulatory Commission (to be used when 
referencing Commission Orders).
    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.
    Interior: United States Department of the Interior.
    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.)
    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.).
    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 ratio.
    Preference: The requirements of Reclamation Law which provide 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 
(Reclamation Project Act of 1939, section 9(c), 43 U.S.C. 485h(c)).
    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: A document explaining the rationale and background 
for the rate proposal contained in this Rate Order dated June 2005.
    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 and deferred expenses) and repay Federal investments and other 
assigned costs.
    RMR: The Rocky Mountain Customer Service Region of Western.
    UGPR: The Upper Great Plains Customer Service Region of Western.
    Western: 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 January 1, 2006, and 
will remain in effect until December 31, 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 April 19, 2005, when 
Western mailed a notice announcing informal customer meetings to all P-
SMBP--ED customers and interested parties. The meetings were held on 
May 10, 2005, in Denver, Colorado, and on May 11, 2005, 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. An FRN was published on June 16, 2005 (70 FR 35080) that 
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 June 17, 2005, Western's UGPR mailed letters to all P-SMBP--
ED preference customers and interested parties transmitting the FRN 
published on June 16, 2005.
    4. On July 19, 2005, beginning at 10 a.m. (MDT), Western held a 
public information forum at the Radisson Stapleton Plaza in Denver, 
Colorado. On July 20, 2005, beginning at 8 a.m. (CDT), a second public 
information forum was held at Peru State College in Lincoln, Nebraska. 
On July 20, 2005, beginning at 2 p.m. (CDT), a third public information 
forum was held at the Sheraton Hotel and Convention Center in Sioux 
Falls, South Dakota. On July 21, 2005, beginning at 9 a.m. (CDT), a 
fourth public information forum was held at the Doublewood Inn in 
Fargo, North Dakota. Western provided detailed explanations of the 
proposed rates for P-SMBP--ED, and a list of issues that could change 
the proposed rates. Western also answered questions and gave notice 
that more information was available in the rate brochure.
    5. On August 16, 2005, beginning at 9 a.m. (MDT), Western held a 
comment forum at the Radisson Stapleton Plaza in Denver, Colorado, to 
give the public an opportunity to comment for the record. No oral or 
written comments were received at this forum. On August 17, 2005, 
beginning at 9 a.m. (CDT), a second public comment forum was held at 
the Sheraton Hotel and Convention Center in Sioux Falls, South Dakota, 
to give the public an opportunity to comment for the record. Ten oral 
comments were received at this forum.
    6. Western received 92 comment letters and 21 verbal comments from 
94 entities during the consultation and comment period, which ended 
September 14, 2005. All formally submitted comments have been 
considered in preparing this Rate Order.

[[Page 71283]]

    7. Western's UGPR provided a Web site with all of the letters, time 
frames, dates and locations of forums, documents discussed at the 
information meetings, FRNs, and all other information about this rate 
process for easy customer access. The Web site is located at https://
www.wapa.gov/ugp/rates/2006FirmRateAdj.

Comments

    Written comments were received from the following organizations:

Atlantic Municipal Utilities, Iowa
Basin Electric Power Cooperative, North Dakota
Breckenridge Public Utilities, Minnesota
Brown County Rural Electrical Association, Minnesota
Capital Electric Cooperative, Inc., North Dakota
Central Iowa Power Cooperative, Iowa
Central Power Electric Cooperative, Inc., North Dakota
City of Adrian, Minnesota
City of Akron, Iowa
City of Arlington, South Dakota
City of Auburn, Nebraska
City of Aurora, South Dakota
City of Benson, Minnesota
City of Big Stone City, South Dakota
City of Burke, South Dakota
City of Colman, South Dakota
City of Detroit Lakes, Minnesota
City of Estelline, South Dakota
City of Faith, South Dakota
City of Flandreau, South Dakota
City of Fort Pierre, South Dakota
City of Groton, South Dakota
City of Hawarden, Iowa
City of Howard, South Dakota
City of Jackson, Minnesota
City of Lakota, North Dakota
City of Luverne, Minnesota
City of Madison, South Dakota
City of McLaughlin, South Dakota
City of Melrose, Minnesota
City of Northwood, North Dakota
City of Orange City, Iowa
City of Parker, South Dakota
City of Paullina, Iowa
City of Pierre, South Dakota
City of Plankinton, South Dakota
City of Sioux Center, Iowa
City of Staples, Minnesota
City of Tyndall, South Dakota
City of Vermillion, South Dakota
City of Wadena, Minnesota
City of Watertown, South Dakota
City of Wessington Springs, South Dakota
City of White, South Dakota
City of Winner, South Dakota
Corn Belt Power Cooperative, Iowa
Dakota State University, South Dakota
Dawson Public Power District, Nebraska
East River Electric Power Cooperative, South Dakota
Federated Rural Electric, Minnesota
Hartley Municipal Utilities, Iowa
Heartland Consumers Power District, South Dakota
Lake Region Electric Cooperative, Minnesota
Lincoln Electric System, Nebraska
Manilla Municipal Utilities, Iowa
Marshall Municipal Utilities, Minnesota
McLeod Cooperative Power, Minnesota
Meeker Cooperative, Minnesota
Mid-West Electric Consumers Association, Colorado
Minnkota Power Cooperative, Inc., North Dakota
Missouri River Energy Services, South Dakota
Moorhead Public Service, Minnesota
Municipal Energy Agency of Nebraska, Nebraska
Nebraska Public Power District, Nebraska
Nobles Cooperative Electric, Minnesota
Northwest Iowa Power Cooperative, Iowa
Powder River Energy Corporation, Wyoming
Renville Sibley Cooperative Power Association, Minnesota
Rock Rapids Utilities, Iowa
Sanborn Municipal Light Plant, Iowa
Sauk Centre Public Utilities Commission, Minnesota
Sioux Valley Energy, South Dakota
Slope Electric Cooperative, Inc., North Dakota
South Dakota Municipal Electric Association, South Dakota
South Dakota Rural Electric Association
State of Montana-Department of Natural Resources and Conservation
State of South Dakota-Black Hills State University
State of South Dakota-Board of Regents
State of South Dakota-Bureau of Administration
State of South Dakota-Department of Corrections
State of South Dakota-Developmental Center/Redfield
State of South Dakota-Human Services Center
State of South Dakota-Mike Durfee State Prison
State of South Dakota-Northern State University
State of South Dakota-School of Mines and Technology
State of South Dakota-South Dakota State Penitentiary
State of South Dakota-South Dakota State University
Town of Pickstown, South Dakota
Town of Langford, South Dakota
Valley City Public Works, North Dakota
Valley Electric Cooperative, Montana
Woodbine Municipal Utilities, Iowa
    Representatives of the following organizations made oral comments:

Basin Electric Power Cooperative, North Dakota
City of Barnesville, Minnesota.
City of Harlan, Iowa
City of Wadena, Minnesota
East River Electric Power Cooperative Inc., South Dakota
Federated Rural Electric, Minnesota
Lake Region Electric Cooperative, Minnesota
Lincoln Electric System, Nebraska
Mid-West Electric Consumers Association, Colorado
Minnkota Power Cooperative Inc., North Dakota
Missouri River Energy Services, South Dakota
Moorhead Public Service, Minnesota
Nebraska Public Power District, Nebraska
Valley City Public Works, North Dakota

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. The 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, Minnesota, Montana east of the Continental Divide, North 
Dakota, South Dakota and the eastern two-thirds of Nebraska. The RMR 
markets P-SMBP power and Fry-Ark power, which in combination with P-
SMBP--WD is known as LAP power, in northeastern Colorado, east of the 
Continental Divide

[[Page 71284]]

in Wyoming, west of the 101st meridian in Nebraska and northern Kansas. 
The P-SMBP power is marketed to approximately 300 firm power customers 
by the UGPR and approximately 40 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 revenues. 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 to meet future obligations.
    Under this adjustment, payments toward irrigation assistance and 
capital debt are necessary before deficits are completely repaid. 
Traditionally, prepayment of irrigation assistance or capital is only 
done in the absence of deficits. However, if all revenue were applied 
toward deficits prior to making any payments for irrigation and other 
capital requirements, an extraordinarily large rate increase to meet 
single year repayment obligations would be required. Once these single 
year repayment obligations were satisfied, another rate adjustment 
would be necessary to decrease the rates. While repayment of capital 
debt and irrigation assistance prior to complete repayment of deficits 
is not typical, the approach approved within this Rate Order is well 
within the bounds of the discretion allowed under DOE Order RA 6120.2.
    Under this adjustment, Western will repay all deficits and also 
make previously planned payments for irrigation assistance and other 
investments that are due in the years 2013 and 2014. Prepaying 
irrigation and capital investments has been part of the Pick-Sloan 
repayment plans and approved rate adjustments for the past 20 years. 
They are an integral part of the long-term plan for the project and 
have provided rate stability for consumers while meeting Federal 
repayment obligations. Modest irrigation and investment payments for a 
brief period of 2 to 3 years will reduce the single-year revenue 
requirement for irrigation assistance and hold increases to the 
``lowest possible rates to consumers consistent with sound business 
principles,'' as outlined in section 5 of the Flood Control Act of 
1944.
    The provisional rates for P-SMBP--ED will be implemented in two 
steps. First step provisional rates are to become effective on an 
interim basis on the first day of the first full billing period 
beginning on or after January 1, 2006. Second step provisional rates 
are to become effective on the first day of the first full billing 
period beginning on or after January 1, 2007. Under Rate Schedule P-
SED-F8, the first and second step provisional rates for P-SMBP--ED firm 
power will result in a total compounded composite rate increase of 
approximately 18.4 percent. The current composite rate under Rate 
Schedule P-SED-F7 is 16.51 mills/kWh. The provisional composite rate is 
19.54 mills/kWh.

Existing and Provisional Rates

    A comparison of the existing and provisional firm power and firm 
peaking power rates follow:

        Comparison of Existing and Provisional Rates Pick-Sloan Missouri Basin Program--Eastern Division
----------------------------------------------------------------------------------------------------------------
                                                                                      Second step
     Firm electric service        Existing rates    First step rates    Percent     rates  Jan. 1,     Percent
                                                      Jan. 1, 2006       change          2007           change
----------------------------------------------------------------------------------------------------------------
P-SMBP--ED Revenue Requirement  $160.1 million...  $179.4 million...         12.1  $189.9 million..          5.9
P-SMBP--ED Composite Rate.....  16.51 mills/kWh..  18.47 mills/kWh..         11.9  19.54 mills/kWh.          5.8
Firm Capacity.................  $3.72/kWmonth....  $4.20/kWmonth....         12.9  $4.45/kWmonth...          6.0
Firm Energy...................  9.62 mills/kWh...  10.69 mills/kWh..         11.1  11.29 mills/kWh.          5.6
Tiered > 60 Percent Load        5.21 mills/kWh...  5.21 mills/kWh...          0.0  5.21 mills/kWh..          0.0
 Factor.
Firm Peaking Capacity.........  $3.72/kWmonth....  $4.20/kWmonth....         12.9  $4.45/kWmonth...          6.0
Firm Peaking Energy \1\.......  9.62 mills/kWh...  10.69 mills/kWh..         11.1  11.29 mills/kWh.         5.6
----------------------------------------------------------------------------------------------------------------
\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 will be designed to cover 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-125. Rate Order No. WAPA-125 is also 
scheduled to go into effect on the first day of the first full billing 
period beginning on January 1, 2006.

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 O&M and 
other annual expenses, increased investments, and increased interest 
expense associated with deficits. The studies have also been adjusted 
to account for calendar year implementation versus a fiscal year 
implementation.
    The existing rates for P-SMBP--ED firm power and firm peaking power 
under Rate Schedules P-SED-F7 and P-SED-FP7 expire December 31, 2008. 
Effective January 1, 2006, Rate Schedules P-SED-F7 and P-SED-FP7 will 
be superseded by the new rates in Rate Schedule P-SED-F8s and Rate 
Schedule P-SED-FP8. The provisional rates for P-SED-F8 firm power 
consist of a capacity charge and an energy charge. The provisional 
capacity charge is $4.45/kWmonth, and the provisional energy charge is 
11.29 mills/kWh.

[[Page 71285]]

Statement of Revenue and Related Expenses

    The following table provides a summary of projected revenue and 
expense data for the P-SMBP--ED firm power rate through the 5-year 
provisional rate approval period.

      P-SMBP--ED 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..................................................      $1,497,654      $1,694,242        $196,588
Revenue Distribution
    Expenses:
        O&M.....................................................         762,873         832,279          69,406
        Purchased Power and Wheeling............................          60,882         276,203         215,320
        Integrated Projects Requirements........................               0               0               0
        Interest................................................         435,196         482,809          47,613
        Transmission............................................          67,063          70,537           3,474
                                                                 -----------------
            Total Expenses......................................       1,326,014       1,661,827         335,813
    Principal Payments:
        Capitalized Expenses....................................         169,152          30,764       (138,388)
        Original Project and Additions \1\......................           1,128           1,128               0
        Replacements \1\........................................           1,360             523           (837)
        Irrigation..............................................               0               0               0
                                                                 -----------------
            Total Principal Payments............................         171,641          32,416       (139,225)
                                                                 =================
            Total Revenue Distribution..........................       1,497,654       1,694,242        196,588
----------------------------------------------------------------------------------------------------------------
\1\ Due to the deficit or near-deficit conditions between 1999 and 2007, 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-F7 expire December 31, 2008. The existing rates 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 O&M and other annual expenses, increased 
investments, and increased interest expense associated with deficits. 
The studies have also been adjusted to account for calendar year 
implementation versus fiscal year implementation. 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 
January 1, 2006, to correspond with the start of the calendar year, and 
will remain in effect through December 31, 2010.
    The P-SMBP--ED provisional firm power rate is designed to recover 
50 percent of the revenue requirement from the capacity rate and 50 
percent from the energy rate. The capacity rate of $4.45 per kWmonth is 
calculated by dividing 50 percent of the total annual revenue by the 
number of billing units (kWmonths) in a year. The energy rate of 11.29 
mills/kWh is calculated by dividing 50 percent of the total annual 
revenue requirement by the annual energy sales. The capacity rate is 
applied to both firm power and firm peaking power. The energy rate is 
applied to firm energy and firm peaking energy that is not returned to 
Western.
    The P-SMBP--ED firm peaking rate is equal to the capacity charge 
for the firm power rate. The firm peaking customer pays the capacity 
rate on their total firm peaking CROD each month rather than firm 
peaking delivered each month. Contract terms vary among firm peaking 
customers with respect to return of peaking energy. One firm peaking 
customer returns all peaking energy, while the other peaking customer 
may pay for 20 to 40 percent of the peaking energy they use and return 
the rest to Western. When a firm peaking customer keeps peaking energy 
the rate paid is the same as the firm energy rate.

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.
    A. Comment: Western received numerous comments that strongly 
supported Western's original rate adjustment proposal which included a 
2-step adjustment, calendar year implementation, no change to the 
tiered rate, and the proposed rates.
    Response: Western appreciates the support it has received from the 
public for the original rate adjustment proposal.
    B. Comment: One customer commented that Western should spread this 
rate increase into future years to help lessen the impact to its 
customers. Western received one comment preferring equal increases in 
each of the 2 years rather than the proposed approximate two-thirds and 
one-third plan.
    Response: In accordance with DOE Order RA 6120.2, Western set the 
rate such that it is the lowest possible consistent with sound business 
principles. By adopting the 2-step rate adjustment, Western has spread 
the impact of the rate increase on the customers over a longer time. 
Spreading the rate increase over additional years or equal rate 
increases would cause the cumulative deficit to increase substantially 
and would not be consistent with sound business principles.
    C. Comment: During the comment period, Western received 90 written 
comments and 21 verbal comments concerning the proposed Peaking Power 
Capacity Alternative. By far, most commenters indicated that Western 
should not accept the Peaking Power

[[Page 71286]]

Capacity Alternative because implementing a change in rate methodology 
would require a new rate design. Commenters also stated that shifting 
costs from firm peaking capacity customers to firm power customers is 
inappropriate, inequitable, and unjustified. Commenters suggested that 
peaking customers are getting a superior product, particularly in the 
summer season, to what other firm power customers are getting because 
they do not take as much off-peak energy, are not subject to load 
following scheduling limitations, and have very generous energy payback 
provisions or can buy high-value energy at the firm power rate. One 
peaking supporter commented that Western is obligated to act in the 
best interest of the entire customer base.
    Several comments stated that Western should accept the Peaking 
Power Capacity Alternative based on it being more equitable in 
distributing the costs driving the rate increase. It was stated that 
due to the drought Western has purchased power, both on and off peak, 
in every month and given the terms of the peaking contracts, it is not 
equitable to include all these costs in the peaking customers' rates 
because they do not receive energy in every month. These commenters 
suggested that requiring peaking customers to pay a demand charge in 
months of no usage penalizes these customers and significantly 
increases the cost of power purchased under the peaking contract. 
Additionally, comments state that the peaking contract load factor has 
decreased since the inception of the contract and is significantly 
lower than the firm contract load factor. One firm peaking power 
customer stated that the effective cost of peaking power in 2004, after 
return of energy to Western, was $304/MWh in the summer and $2,914/MWh 
in the winter season. Another firm peaking power customer stated that 
its average per unit cost of firm power was $17.57/MWh and the cost for 
peaking power was $3,750/MWh. That customer also commented it 
participates in the energy markets on a daily basis and understands the 
value of the peaking contract. It stated this cost comparison is not 
used to prove that firm peaking is overpriced; instead it demonstrates 
that the products are different. Lastly, several comments suggest that 
operating applications under the contract are too restrictive.
    Response: Because several customers indicated there was rate 
inequity between the firm peaking power product and the firm power 
product, Western included the Peaking Power Capacity Alternative in the 
Notice of Proposed Power Rates. Outlining the concerns of the peaking 
customers gives the public an opportunity to provide reasonable and 
logical documentation indicating that there is an inequity in rates 
charged for the firm peaking power product and the firm power product 
through the public process. While firm peaking power customers do 
receive several benefits from the firm peaking power product beyond 
those available to firm power product customers, Western does not 
recognize the firm peaking power product to be superior to the firm 
power product. Western does not find that comments supporting the 
Peaking Power Capacity Alternative provide an in-depth evaluation with 
supporting data to demonstrate inequities in charges between the 
products. To support the rate inequity between the firm power product 
and the peaking power product, a few comments used an energy cost 
analysis. In determining the true value of the firm peaking power 
product, Western believes it is unreasonable to focus solely on the 
energy component while ignoring the benefits of the capacity portion of 
the product. Comments supporting the Peaking Power Capacity Alternative 
also point to energy purchases as the majority of costs requiring the 
rate adjustment. They make the argument that energy purchase costs due 
to drought conditions are primarily associated with the firm power 
product and, therefore, a larger portion of the rate adjustment should 
be attributed to the firm power product. A thorough analysis of 
inequities between the firm peaking power product and the firm power 
product must look at the effect of energy sales as well as energy 
purchases. While it is true that energy purchases during a drought 
apply upward pressure on Western's rates, it is also true that surplus 
sales apply downward pressure during high water years. The comments 
fail to recognize that non-firm energy sales are the primary reason 
that both the firm peaking power product and the firm power product 
both enjoyed flat rates for the 10 years preceding the current drought 
period.
    Western has determined that the rate increase should be spread 
among both firm power and firm peaking power customers following the 
practice historically used. Those comments received regarding the 
restrictions to the operational application of the firm peaking power 
product are outside the scope of this rate adjustment process. However, 
Western is willing to look at the operational applications and review 
possible restrictions to ensure equity in the firm peaking power 
product for all firm peaking power customers through Western's normal 
contract administration procedures. After considering the comments, 
Western has determined at this time it cannot justify moving to the 
Firm Peaking Capacity Alternative.
    D. Comment: Western received one comment of concern that adequate 
long-term purchased power arrangements have not been pursued by the 
UGPR.
    Response: Western continues to look into long-term purchased power 
arrangements on a seasonal basis. However, at this time long-term 
purchases that are available are not the most cost beneficial method of 
meeting Western purchase power requirements.
    E. Comment: Western received one comment that encouraged Western to 
investigate ways to maximize the value of its assets, including 
transmission rights across neighboring systems and high-value 
transmission rights across constrained paths.
    Response: Western continually looks for ways to increase revenues 
and decrease costs, including maximizing the use of the transmission 
system. However, Western has determined that this particular comment is 
not directly related to the proposed action and is outside the scope of 
this rate process.

Availability of Information

    Information about this rate adjustment, including PRSs, comments, 
letters, memorandums and other supporting material made or kept by 
Western 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.

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

[[Page 71287]]

on Environmental Quality Regulations (40 CFR parts 1500-1508); and DOE 
NEPA Regulations (10 CFR part 1021), Western has determined that this 
action is categorically excluded from preparing an environmental 
assessment or an environmental impact statement.

Determination Under Executive Order 12866

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

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 provisional 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 January 1, 2006, 
Rate Schedules P-SED-F8 and P-SED-FP8 for the Pick-Sloan Missouri Basin 
Program--Eastern Division of the Western Area Power Administration. The 
rate schedules 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 December 31, 2010.

    Dated: November 9, 2005.

Clay Sell,

Deputy Secretary.

Rate Schedule P-SED-F8; (Supersedes Schedule P-SED-F7)

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

Effective

First Step
    The first day of the first full billing period beginning on or 
after January 1, 2006, through December 31, 2006.
Second Step
    Beginning on the first day of the first full billing period 
beginning on or after January 1, 2007, through December 31, 2010.

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 and Conditions of Service

    Alternating current, 60 hertz, three-phase, delivered and metered 
at the voltages and points established by contract.

Monthly Rate

First Step
    Demand Charge: $4.20 for each kilowatt per month (kWmonth) of 
billing demand.
    Energy Charge: 10.69 mills for each kilowatthour (kWh) for all 
energy delivered as firm power service. An additional charge of 5.21 
mills/kWh, for a total of 15.90 mills/kWh, will be assessed for all 
energy delivered as firm power service that is in excess of a 60-
percent monthly load factor and within the delivery obligations under 
the provisions of the power sales contract.

Billing Demand

    The billing demand will be as defined by the power sales contract.
Second Step
    Demand Charge: $4.45 for each kWmonth of billing demand.
    Energy Charge: 11.29 mills for each kWh for all energy delivered as 
firm power service. An additional charge of 5.21 mills/kWh for a total 
of 16.50 mills/kWh will be assessed for all energy delivered as firm 
power service that is in excess of a 60 percent monthly load factor and 
within the delivery obligations under the provisions of the power sales 
contracts.

Billing Demand

    The billing demand will be as defined by the power sales contract.

Adjustment 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 capacity 
and energy charges when facilities are provided by the customer that 
result 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.

Adjustment 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.

Adjustment 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.

Schedule of Rates for Firm Peaking Power Service

Effective

First Step
    The first day of the first full billing period beginning on or 
after January 1, 2006, through December 31, 2006.
Second Step
    Beginning on the first day of the first full billing period 
beginning on or after January 1, 2007, through December 31, 2010.

Available

    Within the marketing area served by the Eastern Division of the 
Pick-Sloan Missouri Basin Program, to our 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 and Conditions of Service

    Alternating current, 60 hertz, three-phase, delivered and metered 
at the voltages and points established by contract.

[[Page 71288]]

Monthly Rate

First Step
    Demand Charge: $4.20 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: 10.69 mills for each kilowatthour (kWh) for all 
energy scheduled for delivery without return.

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.
Second Step
    Demand Charge: $4.45 for each kWmonth of the effective contract 
rate of delivery for peaking power or the maximum amount scheduled, 
whichever is greater.
    Energy Charge: 11.29 mills for each kWh for all energy scheduled 
for delivery without return.

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.

Adjustment for 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 capacity and/or energy, such overrun shall be billed at 10 
times the above rate.

[FR Doc. E5-6576 Filed 11-25-05; 8:45 am]
BILLING CODE 6450-01-P