[Federal Register Volume 59, Number 14 (Friday, January 21, 1994)]
[Unknown Section]
[Page 0]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 94-1487]


[[Page Unknown]]

[Federal Register: January 21, 1994]


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DEPARTMENT OF ENERGY
 

Pick-Sloan Missouri Basin Program-Eastern Division--Notice of 
Rate Order No. WAPA-60

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of Rate Order--Pick-Sloan Missouri Basin Program-Eastern 
Division (P-SMBP-ED) firm electric service rate adjustment.

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

SUMMARY: Notice is given of the confirmation and approval by the Deputy 
Secretary of the Department of Energy (DOE) of Rate Order No. WAPA-60 
and Rate Schedules P-SED-F6 and P-SED-FP6 placing increased firm power 
and firm peaking power rates for the P-SMBP-ED into effect on an 
interim basis. The interim rates, called the provisional rates, will 
remain in effect on an interim basis 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. A 
comparison of existing and provisional rates follows: 

                                                        Eastern Division Provisional Rate Changes                                                       
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                           Provisional rates February 1,   Provisional rates October 1, 
                    Type of service                               Existing rates             1994, and percent change        1994, and percent change   
--------------------------------------------------------------------------------------------------------------------------------------------------------
FIRM COMMERCIAL:                                                                                                                                        
    Composite Rate......................................  12.16 (mills/kWh).............  13.31 (mills/kWh) 9.5%........  14.23 (mills/kWh) 7.0%.       
    Firm Energy.........................................  7.09 (mills/kWh)..............  7.76 (mills/kWh) 9.5%.........  8.32 (mills/kWh) 7.2%.        
    Firm Capacity.......................................  $2.74/kW-month................  $3.00/kW-month, 9.5%..........  $3.20/kW-month 6.7%.          
    Tiered > 60 percent L.F.............................  3.38 (mills/kWh)..............  3.38 mills/kWh................  3.38 mills/kWh.               
Firm Peaking:                                                                                                                                           
    Peaking Capacity....................................  $2.74/kW-month................  $3.00/kW-month, 9.5%..........  $3.20/kW-month, 6.7%.         
    Peaking Energy......................................  7.09 mills/kWh................  7.76 (mills/kWh) 9.5%.........  8.32 (mills/kWh) 7.2%.        
--------------------------------------------------------------------------------------------------------------------------------------------------------


DATES: Rate Schedules P-SED-F6 and P-SED-FP6 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, 1994, and will be in effect until 
FERC confirms, approves, and places the rate schedules into effect on a 
final basis for a 5-year period, or until the rate schedules are 
superseded.

FOR FURTHER INFORMATION CONTACT:

Mr. James D. Davies, Area Manager, Billings Area Office, Western 
Area Power Administration, P.O. Box 35800, Billings, MT 59107-5800, 
(406) 657-6532;
Ms. Deborah M. Linke, Director, Division of Marketing and Rates, 
Western Area Power Administration, P.O. Box 3402, Golden, CO 80401-
3398, (303) 231-1545;
Mr. Joel Bladow, Assistant Administrator for Washington Liaison, 
Western Area Power Administration, Room 8G-061, Forrestal Building, 
1000 Independence Avenue SW., Washington, DC 20585-0001, (202) 586-
5581.

SUPPLEMENTARY INFORMATION: By Amendment No. 3 to Delegation Order No. 
0204-108, published November 10, 1993 (58 FR 59716), the Secretary of 
Energy delegated (1) the authority to develop long-term power and 
transmission rates on a nonexclusive basis to the Administrator of 
Western Area Power Administration (Western); (2) the authority to 
confirm, approve, and place such rates into effect on an interim basis 
to the Deputy Secretary; 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 DOE procedures for public participation in 
power rate adjustments (10 CFR part 903) became effective on September 
18, 1985 (50 FR 37835).
    These power rates are established pursuant to section 302(a) of the 
DOE Organization Act, 42 U.S.C. 7152(a), through which the power 
marketing functions of the Secretary of the Interior and the Bureau of 
Reclamation (Reclamation) under the Reclamation Act of 1902, 43 U.S.C. 
371 et seq., as amended and supplemented by subsequent enactments, 
particularly section 9(c) of the Reclamation Project Act of 1939, 43 
U.S.C. 485h(c), and other acts specifically applicable to the project 
system involved, were transferred to and vested in the Secretary of 
Energy (Secretary).
    Discussions on the proposed rate adjustments were initiated on 
January 26, 1993, when a letter announcing the preliminary informal 
customer meetings was mailed to all firm power customers and other 
interested persons. These meetings were conducted at four different 
locations on February 5, 8, 9, and 10, 1993. At these preliminary 
meetings, Western representatives explained the need for the rate 
increases and answered questions from those attending.
    The consultation and comment period was initiated on July 8, 1993, 
with publication of a Federal Register notice (58 FR 36684) that 
officially announced the proposed rate adjustments and procedures for 
public participation. The Federal Register notice announced a series of 
public information forums that were held on July 20, and August 9-11, 
1993, in Northglenn, Colorado; Sioux Falls, South Dakota; Fargo, North 
Dakota; and Billings, Montana. Public comment forums were held in 
Northglenn, Colorado, and Sioux Falls, South Dakota, on August 30 and 
31, 1993, respectively. The consultation and comment period concluded 
October 6, 1993.
    During the comment period, Western received 10 comment letters on 
the Pick-Sloan Missouri Basin Program (P-SMBP) rate adjustment. At the 
August 30 and 31, 1993, public comment forums, one person commented 
orally. All comments were considered in preparation of the rate order. 
Western has concluded that the P-SMBP rate adjustments are needed to 
meet cost-recovery criteria.
    The proposed rate adjustments are based upon the fiscal year (FY) 
1992 power repayment study (PRS). To prepare the ratesetting PRS, 
Western considered projections which will be used in the final FY 1993 
PRS. Western's objective is to mitigate the rapidly increasing deficits 
due to reduced surplus sales revenue and increasing purchased power 
expense resulting from the drought on the P-SMBP. Using this concept, 
Western developed a two-step rate adjustment. The first step is based 
upon the FY 1992 PRS with 5 future years of purchased power expense and 
1 future year of reduced surplus sales revenue. The second step is 
based on the FY 1992 PRS utilizing 5 years of projected increased 
purchased power expense and reduced surplus sales revenue for 1 year. 
In the second step, Western also included expected increases in 
operations and maintenance (O&M) expenses and 1 additional year of 
power investment. By implementing this two-step rate adjustment, 
Western is providing P-SMBP customers with a more accurate basis for 
budgeting their future power costs as well as mitigating the impact of 
the rate increases.
    In Rate Order No. WAPA-60, results of the ratesetting PRS are being 
compared to the FY 1990 PRS, which was the basis for the existing P-
SMBP rates. The comparison shows the following differences:
    1. The projected O&M expenses, including the integrated projects, 
for the 100-year period have increased a total of $10.2 million per 
year.
    2. Purchased power projected over the future 6-year period is $113 
million. These costs are partially attributable to the extended drought 
which necessitated the Bureau of Reclamation and the Corp of Engineers 
to draw down the reservoirs to an extremely low level. This has caused 
Western to project future purchased power expenses for the next few 
years until the reservoirs are full again. Although FY 1993 was an 
above-average water year, purchased power expenses are continuing to be 
projected because the flooding in the Midwest severely restricted water 
releases and therefore severely curtailed power generation.
    3. Reduced surplus sales and increased purchased power costs 
appearing historically in the study, as a result of the drought in the 
Missouri Basin, have now accumulated $126 million in unpaid annual 
expenses, which have been capitalized. These and expected unpaid annual 
expenses over the next 2 years are projected to be repaid by 2002.
    4. The power investments projected over the future 6-year period 
are $286 million. New power investments, other than replacements, are 
not projected beyond the 6-year period.
    Of the above factors, the one item with the greatest rate impact is 
the drought, which is reflected in the purchased power expenses and 
capitalized unpaid annual expenses. The second greatest impact comes 
from O&M expenses, which are increasing due to inflation as well as 
responding to programmatic and administrative requirements, such as 
safety programs and environmental compliance.
    Rate Order No. WAPA-60, confirming, approving, and placing the 
proposed P-SMBP-ED rate adjustments into effect on an interim basis, is 
issued, and the new Rate Schedules P-SED-F6 and P-SED-FP6 will be 
submitted promptly to FERC for confirmation and approval on a final 
basis.

    Issued in Washington, DC, January 6, 1994.
Bill White,
Deputy Secretary.

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

    In the matter of: Western Area Power Administration Rate 
Adjustments for Pick-Sloan Missouri Basin Program-Eastern Division, 
Rate Order No. WAPA-60

January 6, 1994.
    These power rates are established pursuant to section 302(a) of the 
Department of Energy (DOE) Organization Act, 42 U.S.C. 7152(a), through 
which the power marketing functions of the Secretary of the Interior 
and the Bureau of Reclamation (Reclamation) under the Reclamation Act 
of 1902, 43 U.S.C. 371 et seq., as amended and supplemented by 
subsequent enactments, particularly section 9(c) of the Reclamation 
Project Act of 1939, 43 U.S.C. 485h(c), and other acts specifically 
applicable to the Pick-Sloan Missouri Basin Program (P-SMBP), were 
transferred to and vested in the Secretary of Energy.
    By Amendment No. 3 to Delegation Order No. 0204-108, published 
November 10, 1993 (58 FR 59716), the Secretary of Energy delegated (1) 
the authority to develop long-term power and transmission rates on a 
nonexclusive basis to the Administrator of the Western Area Power 
Administration (Western); (2) the authority to confirm, approve, and 
place such rates into effect on an interim basis to the Deputy 
Secretary; 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) became 
effective on September 18, 1985 (50 FR 37835).

Acronyms and Definitions

    As used in this rate order, the following acronyms and definitions 
apply:

$/kW-month: Monthly charge for capacity (usage - Sec. per kilowatt-
month).
BAO: Western's Billings Area Office.
Corps: U.S. Army Corps of Engineers.
Criteria: Post-1989 General Power Marketing and Allocation Criteria; 
Pick-Sloan Missouri Basin Program-Western Division, 51 FR 4012 
(January 31, 1986) and Eastern Division Pick-Sloan Missouri Basin 
Program Final Post-1985 Marketing Plan, 45 FR 71860 (October 30, 
1980).
CROD: Contract Rate of Delivery.
Customer Brochure: A document prepared for public distribution 
explaining the background of the rate proposal contained in this 
rate order.
DOE: Department of Energy.
DOE Order RA 6120.2: An order dealing with power marketing 
administration financial reporting.
FERC: Federal Energy Regulatory Commission.
Fry-Ark: Fryingpan-Arkansas Project.
FY: Fiscal year.
Interior: U.S. Department of the Interior.
kW: Kilowatt.
kW-month: The greater of (1) the highest 30-minute demand measured 
during the month, not to exceed the contract obligation, or (2) the 
contract rate of delivery.
kWh: Kilowatthour.
LAO: Western's Loveland Area Office.
LAP: Loveland Area Projects.
M&I: Municipal and industrial.
mills/kWh: Mills per kilowatthour.
MW: Megawatt.
O&M: Operation and maintenance.
pinch-point: The FY in which the level of the rate is set as 
dictated by a revenue requirement in that future year to meet 
relatively large annual costs or to repay investments which come 
due.
PMA: Power marketing administration.
PRS: Power repayment study.
P-SED-F5: Pick-Sloan Eastern Division's existing rate schedule for 
firm power service.
P-SED-F6: Pick-Sloan Eastern Division's provisional rate schedule 
for firm power service.
P-SED-FP5: Pick-Sloan Eastern Division's existing rate schedule for 
firm peaking service.
P-SED-FP6: Pick-Sloan Eastern Division's provisional rate schedule 
for firm peaking service.
P-SMBP: 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.
Reclamation: Bureau of Reclamation, U.S. Department of the Interior.
Treasury: Secretary of the Department of the Treasury.
Western: Western Area Power Administration, U.S. Department of 
Energy.

Effective Date

    The new rates will become effective on an interim basis on the 
first day of the first full billing period beginning on or after 
February 1, 1994, and will be in effect pending FERC's approval of 
them, or substitute rates, on a final basis for a 5-year period, or 
until superseded.

Public Notice and Comment

    The procedures for public participation in power and transmission 
rate adjustments and extensions, 10 CFR part 903, have been followed by 
Western in the development of these firm power rates. These firm power 
rates represent an increase of more than 1 percent in total P-SMBP-ED 
revenues; therefore, it is a major rate adjustment as defined at 10 CFR 
903.2(e) and 903.2(f)(1). The distinction between a minor and a major 
rate adjustment is used only to determine the public procedures for the 
rate adjustment.
    The following summarizes the steps Western took to ensure 
involvement of interested parties in the rate process:
    1. Discussion of the proposed rate adjustments was initiated on 
January 26, 1993, when a letter announcing informal customer meetings 
was mailed to all firm power customers and other interested parties. 
The 1993 meetings were held on the following dates: February 5 in 
Billings, Montana; February 8 in Sioux Falls, South Dakota; February 9 
in Denver, Colorado; and February 10 in Fargo, North Dakota. At these 
informal meetings, Western representatives explained the need for the 
increase and answered questions from those attending.
    2. On March 9, 1993, a customer brochure was mailed to all 
customers and other interested persons. This mailing also included a 
letter announcing the four public information forums and two comment 
forums.
    3. On March 11, 1993, a letter was mailed to all customers and 
other interested persons on the delay of the publishing of the Federal 
Register notice. The public information forums and comment forums were 
also delayed.
    4. A Federal Register notice was published on July 8, 1993 (58 FR 
36684), officially announcing the proposed firm power rate adjustments, 
initiating the public consultation and comment period, announcing the 
information and comment forums, and presenting procedures for 
participation.
    5. On July 14, 1993, letters were mailed to all P-SMBP-ED customers 
and interested persons announcing the publication of the Federal 
Register notice of July 8, 1993. This mailing also included a letter 
announcing four public information forums and two comment forums.
    6. The public information forums were conducted on the following 
dates: July 20 in Northglenn, Colorado; August 9 in Billings, Montana; 
August 10 in Sioux Falls, South Dakota; and August 11 in Fargo, North 
Dakota. At these forums, Western representatives explained the need for 
the rate increases in greater detail and answered questions.
    7. Western received an extensive request for information from one 
customer group. We responded by providing data and background 
information for the ratesetting PRS.
    8. The comment forums were held on August 30, 1993, at Northglenn, 
Colorado, and August 31, 1993, at Sioux Falls, South Dakota, to give 
the public an opportunity to comment for the record. One person 
representing a customer and customer group made oral comment at the 
August 30, 1993, forum. Western received no comments at the August 31, 
1993, forum.
    9. Ten comment letters were received during the 91-day consultation 
and comment period. The consultation and comment period ended October 
6, 1993. All formally submitted comments have been considered in the 
preparation of this rate order.

Project History

    The initial stages of the Missouri River Basin Project were 
authorized by section 9 of the Flood Control Act of 1944 (58 Stat. 877, 
891). The Missouri River Basin Project, later renamed the P-SMBP to 
honor its two principal authors, has been under construction since 
1944. The P-SMBP encompasses a comprehensive program of flood control, 
navigation improvement, irrigation, M&I water development, and 
hydroelectric production for the entire Missouri River Basin.
    Multipurpose projects have been developed on the Missouri River and 
its tributaries in Colorado, Montana, Nebraska, North Dakota, South 
Dakota, and Wyoming.

Power Repayment Studies

    PRSs are prepared each FY to determine if power revenues will be 
sufficient to pay, within the prescribed time periods, all costs 
assigned to the power function. Repayment criteria are based on law, 
policies, and authorizing legislation. DOE Order RA 6120.2, section 
12b, requires that:

    In addition to the recovery of the above costs (operation and 
maintenance and interest expenses) on a year-by-year basis, the 
expected revenues are at least sufficient to recover (1) each dollar 
of power investment at Federal hydroelectric generating plants 
within 50 years after they become revenue producing, except as 
otherwise provided by law; plus, (2) each annual increment of 
Federal transmission investment within the average service life of 
such transmission facilities or within a maximum of 50 years, 
whichever is less; plus, (3) the cost of each replacement of a unit 
of property of a Federal power system within its expected service 
life up to a maximum of 50 years; plus, (4) each dollar of assisted 
irrigation investment within the period established for the 
irrigation water users to repay their share of construction costs; 
plus, (5) other costs such as payments to basin funds, participating 
projects, or States.

Existing and Provisional Rates

Eastern Division

    The existing firm power rates and the provisional firm power rates 
necessary to meet the revenue requirements for the P-SMBP-ED are listed 
below. The provisional rates will be implemented in two steps. Step 1 
rates are to become effective on an interim basis on the first day of 
the first full billing period beginning on or after February 1, 1994. 
Step 2 rates are to become effective on the first day of the first full 
billing period beginning on or after October 1, 1994.
    A comparison of the existing and provisional rates follows: 

                                   Eastern Division Provisional Rate Changes                                    
----------------------------------------------------------------------------------------------------------------
                                                                 Provisional rates,        Provisional rates,   
         Type of service                 Existing rates           February 1, 1994           October 1, 1994    
----------------------------------------------------------------------------------------------------------------
Firm Power Service Rate Schedule:                                                                               
    Composite Rate................  12.16 mills/kWh\1\......  13.31 mills/kWh\2\......  14.23 mills/kWh.\2\     
    Firm Capacity.................  $2.74/kW-month\1\.......  $3.00/kW-month\2\.......  $3.20/kW-month.\2\      
    Firm Energy...................  7.09 mills/kWh\1\.......  7.76 mills/kWh\2\.......  8.32 mills/kWh.\2\      
    Tiered > 60 percent L.F.......  3.38 mills/kWh\1\.......  3.38 mills/kWh\2\.......  3.38 mills/kWh.\2\      
Firm Peaking Power Service Rate                                                                                 
 Schedule:                                                                                                      
    Peaking Capacity..............  $2.74/kW-month\3\.......  $3.00/kW-month\4\.......  $3.20/kW-month.\4\      
    Peaking Energy................  7.09 mills/kWh\3\.......  7.76 mills/kWh\4\.......  8.32 mills/kWh.\4\      
----------------------------------------------------------------------------------------------------------------
\1\P-SED-F5.                                                                                                    
\2\P-SED-F6.                                                                                                    
\3\P-SED-FP5.                                                                                                   
\4\P-SED-FP6.                                                                                                   

Western Division

    The LAP rate will be designed to recover the P-SMBP-WD revenue 
requirements for P-SMBP and the revenue requirements for Fry-Ark. The 
adjustment to the LAP rates is a separate formal procedure which is 
documented in Rate Order No. WAPA-61. Rate Order No. WAPA-61 is also 
scheduled to go into effect on the first day of the first full billing 
period beginning on or after February 1, 1994. The LAP rates will yield 
the revenue requirements for FY 1994-98 for the P-SMBP-WD.

Certification of Rate

    Western's Administrator has certified that the P-SMBP-ED firm power 
rates placed into effect on an interim basis herein are the lowest 
possible consistent with sound business principles. The rates have been 
developed in accordance with administrative policies and applicable 
laws.

Discussion

    Although the P-SMBP is considered a single entity for financial and 
repayment purposes, the power generated by the P-SMBP is marketed in 
two separate and distinct areas. These are known as the Eastern 
Division and the Western Division, and each has its own marketing plan 
and method of designing rates to collect required revenue from power 
sales.
    The existing and provisional revenue requirements for the Eastern 
and Western Divisions for the P-SMBP are as follows: 

               P-SMBP Firm and Peaking Revenue Requirement              
                             [In millions]                              
------------------------------------------------------------------------
                                                   First        Second  
                                                 adjustment   adjustment
                                     Current      February     October  
                                                    1994         1994   
------------------------------------------------------------------------
Eastern Division Firm Commercial.       $103.1       $112.9       $120.8
Eastern Division Peaking.........         12.3         13.5         14.4
                                  --------------------------------------
      Total Eastern Division                                            
       Revenue Requirement.......       $115.4       $126.4      $135.2 
                                  ======================================
Western Division Firm Commercial.         28.0         30.3         31.4
                                  --------------------------------------
      Total P-SMBP Firm and                                             
       Peaking Revenue                                                  
       Requirement...............       $143.4       $156.7      $166.6 
------------------------------------------------------------------------


    The revenue increases are necessary to satisfy the cost-recovery 
criteria set forth in DOE Order RA 6120.2.

Statement of Revenue and Related Expenses

    The following table provides a summary of revenue and expense data 
through the 5-year provisional rate approval period. 

  Pick-Sloan Missouri Basin Program--Comparison of 5-Year Rate Approval 
                                 Period                                 
                    [Revenues and Expenses ($1,000)]                    
------------------------------------------------------------------------
                                   FY 1990 PRS  Ratesetting             
                                     1994-98    PRS 1994-98   Difference
------------------------------------------------------------------------
Total Revenues...................   $1,064,628  $1,199,151     $134,523 
Revenue Distribution:                                                   
    O&M..........................     $540,919    $678,407     $137,488 
    Purchased Power..............        9,300      75,000       65,700 
    Interest.....................      307,913     422,954      115,041 
    Investment Repayment.........      143,233      53,363      (89,870)
    Capitalized Expenses.........            0     (30,573)     (30,573)
    Integrated Projects..........       63,263           0      (63,263)
                                  --------------------------------------
        Total....................   $1,064,628  $1,199,151     $134,523 
------------------------------------------------------------------------

Basis for Rate Development--P-SMBP-ED

    The P-SMBP-ED rates were designed to continue to maintain an 
approximate 50/50 split between revenue earned from the demand and 
energy charges as a basis for the rate design. The revenue yield will 
vary among customers because of a customer's individual load 
characteristics.
    The interim rates contain a $3.00/kW-month firm capacity charge and 
a 7.76 mills/kWh firm energy charge in FY 1994 which will yield the 
necessary revenue for the first year of the rate-approval period, 
effective on the first day of the first full billing period on or after 
February 1, 1994. To provide the additional necessary revenue, an 
increase to $3.20/kW-month firm capacity charge and an 8.32 mills/kWh 
firm energy charge will be in effect on the first day of the first full 
billing period beginning on or after October 1, 1994. The rate-approval 
period terminates on January 31, 1999.

Comments

    During the 91-day comment period, Western received 10 letters 
containing written comments pertaining to this rate adjustment. In 
addition, one person representing a group of customers commented during 
the August 30, 1993, public comment forum. We received no comments at 
the August 31, 1993, forum. All comments were reviewed and considered 
in the preparation of this rate order.
    Written comments were received from the following sources:

Loveland Area Customer Association (Colorado, Wyoming, Kansas, 
Nebraska)
Tri-State Generation and Transmission Association, Inc. (CO, WY, NE)
City of Litchfield (Minnesota)
Lower Brule Sioux Tribe (South Dakota)
Nebraska Public Power District (Nebraska)
City of Lincoln (Nebraska)
Missouri Basin Municipal Power Agency (SD, ND, MN, and IA)
Basin Electric Power Cooperative (ND, SD, MN, IA, MT, WY, and CO)
East River Electric Power Cooperative (South Dakota)

    A representative of the following organizations made an oral 
comment:

Loveland Area Customer Association
Tri-State Generation and Transmission Association, Inc.

    Comments received at the public meetings and in correspondence 
dealt with controlling costs, Eastern Division firm peaking power rate 
design, and projections of revenue and expenses. The comments and 
responses, paraphrased for brevity, are discussed below. Direct quotes 
from comment letters are used for clarification where necessary.
    Issue: Customers suggested that Western should not participate in 
new transmission projects whose cost will affect firm power rates, 
unless the facilities are needed to reliably meet its firm power 
obligations or the facilities will result in net financial savings to 
the firm power revenue requirement.
    Response: Proposals for new facilities must first pass one of three 
criteria before we will consider construction: increased revenues from 
the new facility must exceed the annual cost, or customers must benefit 
sufficiently to support the project in spite of a possible rate 
increase, or the project will be funded from non-Federal sources. We 
will continue our construction program as necessary to ensure we 
provide reliable service.
    Issue: Customers are concerned with the rate at which O&M expenses 
have increased and are projected to increase in the PRS.
    Response: Western received several comments concerned with 
controlling costs related to O&M expenses. One recognized that costs 
appear to be supportable, one asked for mitigation of the rate impact, 
and one suggested an opportunity for review and comment on expenditures 
of Western, the Bureau, and the Corps. Presently, Western has such an 
interaction with the customer group in the Eastern Division of Pick-
Sloan. This comment is from a Western Division customer group. There 
are several Western Division customers who do participate in the 
Eastern Division interaction; the majority of the Western Division 
customer group do not. We propose to extend an invitation to the 
Western Division customer groups to participate in the Eastern Division 
interaction or we will provide a similar opportunity specifically for 
the Western Division.
    One commenter observed that P-SMBP O&M costs have increased at a 
rate that is far greater than the Consumer Price Index (CPI). O&M 
expenses are increasing due to inflation which is reflected in the CPI 
as well as responding to programmatic and administrative requirements, 
such as safety and environmental compliance. These expenses have been 
reviewed both internally by Western and with power customer 
representatives. Western continues to share the power customers' 
concerns with Reclamation and the Corps and has received assurances 
from each agency that each will participate in the cost-containment 
programs associated with O&M functions. Western remains committed to 
cost containment while striving for efficiency and providing customer 
service. Western plans to continue its O&M expense review process with 
power customers and involve customer representatives in its cost-
containment discussions.
    Issue: Customers of firm peaking power have stated that the Eastern 
Division firm peaking rate is arbitrary, unfair, and discriminatory in 
light of the type of service provided by this commodity.
    Response: We received comments from two customers expressing this 
concern. They observed that the capacity charge for firm peaking is 
keyed to the seasonal CROD. That is, the firm peaking customers pay for 
the capacity reserved for them in each month as opposed to the method 
used for the firm commercial customers who pay only for the maximum 
capacity delivered to them each month. They questioned the cost of 
providing capacity for peaking customers vs. firm commercial customers.
    Logic tells us that the costs for providing or reserving capacity 
in the system are the same for each class of service. If we were to 
assume that all fixed costs in a hydro-based system are to be recovered 
by the capacity charge, and since hydro-based systems do not have fuel 
costs, the purchased energy costs are the only variable costs to be 
recovered by the energy charge. This means that the firm commercial and 
firm peaking capacity charge must recover all costs except the 
purchased energy costs which are to be recovered by the energy charge. 
Western traditionally recovers 50 percent of its firm revenue 
requirements from capacity charges and 50 percent from the energy 
charges. Western has chosen this methodology to balance the impact of 
allocating the costs for firm service between customers with a high 
load factor and customers with a low load factor.
    We received comments from a customer supporting the present rate 
design for peaking capacity. One customer stated that they were 
satisfied with the peaking product, but urged Western in its FY 1995 
rate review process to revise its methodology of applying the rate to 
peaking service. In interactions between peaking customers and Western, 
we have discussed several options to make the peaking product more 
flexible to better meet the customers' needs. Many of the options 
discussed would have added more costs to providing the product or 
limited the flexibility of the P-SMBP generating system and, therefore, 
could not be supported by Western.
    Western is not changing the peaking rate methodology at this time. 
However, in the next rate adjustment, we will consider other methods of 
applying the peaking rate or modifying the product.
    Issue: Several customers commented that the second adjustment 
should not be implemented by this rate adjustment process and a second 
rate adjustment process should be performed next year after more facts 
are known.
    Response: In discussions with various customer groups prior to this 
rate adjustment process, we were urged to find a method to limit the 
number of times we proceed through the rate process. This two-step 
process reduces both Western's and its customers' expense associated 
with proceeding through multiple rate adjustment processes. Our 
response to this request is to determine the first rate and project the 
second step. Therefore, assuming our projections are accurate, we will 
have saved the expense of one of two rate adjustment processes. Even 
though we do not expect to process a rate adjustment in the second 
year, we will test our rate and our assumptions in the second year. If 
the projection falls short of repaying the cost of the project, in 
accordance with DOE Order RA 6120.2, we would initiate a rate 
adjustment process. This calls for the question, ``What if the rate is 
too high in the second year?'' The P-SMBP has capitalized $126 million 
of annual expenses through the end of FY 1992. Until that amount is 
repaid, revenues which are surplus to the immediate annual needs of the 
project will be applied to these deficits.
    This two-step rate adjustment has allowed Western's customers to 
better budget and provides a longer-term planning window. When Western 
is not processing a rate adjustment, Western shares the results of its 
annual PRS and supporting data with its customer groups and thoroughly 
reviews the underlying assumptions and results.
    For these reasons, Western is proceeding with the two-step rate 
adjustment.
    Issue: It was suggested by one customer group that Western should 
divide Pick-Sloan revenue requirements between the Eastern and Western 
Divisions on the basis of the firm capacity and energy of each Division 
rather than energy alone, and that this should be done on the basis of 
total revenue requirements rather than the incremental basis presently 
used.
    Response: The different bases for the two marketing plans do not 
readily permit an across-the-board comparison of the capacity available 
from P-SMBP-WD and P-SMBP-ED. It was determined by LAO and BAO that the 
most appropriate method to distribute costs was on the basis of 
contributed energy from each division. This has permitted an ``apples-
to-apples'' comparison of the relative contribution of each division's 
resources while continuing to pool resources and expenses.
    The marketing plans of P-SMBP-ED and LAP were prepared 
independently and take different approaches to the way that capacity is 
marketed. For LAP, capacity is marketed on a fixed basis, with ``take-
or-pay'' amounts for monthly capacity. This capacity is marketed with 
energy at less than the average customer load factor. P-SMBP-ED 
marketed capacity on a proportional basis; that is, capacity is 
marketed as a percentage of each customer's total monthly demand. This 
method is commonly referred to as the ``X/Y'' method. Also, capacity 
for the Eastern Division was marketed with ``load factor'' energy, with 
any remaining capacity resources being marketed as peaking capacity 
without energy.
    Western recognizes that there are numerous ways to market power, 
divide expenses, compute available resources, and forecast future 
impacts. The method chosen to share costs and revenues between the 
Eastern and Western Divisions of P-SMBP is consistent with the 
marketing criteria and represents a fair and equitable solution to the 
customers of both areas. This decision was made with careful 
consideration given to the relative contribution of resources, 
investments, and expenses of each division to the total project. 
Western does not propose to revise the allocation of firm power revenue 
requirements for Eastern and Western Divisions in this rate adjustment. 
Western will continue to observe its revenue-distribution methodology 
to determine if future circumstances necessitate a change, and will 
continue to work with customers to better understand and address these 
concerns.
    Issue: Several customers commented that Western's proposal to 
decrease the amount of firm sales used in the electric service rate 
calculation for LAP was inappropriate and that amount should be 
reallocated, and that there were inconsistencies in the projected level 
of power purchases.
    Response: This issue is applicable only to LAP and, accordingly, is 
discussed in Rate Order No. WAPA-61.
    Issue: Several customers commented that Western's provisional firm 
power rate is too high.
    Response: Several individual customer comments requested mitigation 
of the rate and one customer indicated that although the rate 
adjustments are significant, the adjustments were understandable and 
supportable. A customer group commented that the firm power rate was 
overstated and pointed to several areas where either expense 
projections should be reduced or projections of revenues should be 
increased. We have addressed each of the identified areas as a separate 
issue, and the decision on each is reflected in the response.
    Issue: Western could reduce its purchased power projection by 
utilizing the hydrology projections to forecast purchased power 
requirements.
    Response: Western uses hydrology projections coupled with 
historical experience to project purchased power expense. This 
projection has been increasingly difficult to do in recent years 
because of the drought, as well as the ensuing flood and the endangered 
species operating restrictions. We have found that the purchased power 
expense can be underestimated when the hydrology projections alone are 
used to project purchased power expense. If Western had ignored 
historical purchased power trends and used only hydrology projections 
to forecast purchased power, we would have again underestimated that 
expense. There was so much water downstream, causing the floods in the 
Midwest, the P-SMBP water releases were greatly curtailed, thus 
reducing its generating ability. Western will continue to review its 
projection methods as suggested. The purchased power projection in this 
study, which uses a combination of factors, follows the historical 
trend better than the projection utilizing the hydrology data alone; 
therefore, Western is not revising the projections at this time.
    Issue: Western should update its generation projections to reflect 
the storage condition incurred as a result of the above-average inflows 
for FY 1993.
    Response: The Corps is presently preparing and revising generation 
projections for this very reason. Those projections will be used in 
preparing the next FY's PRS. At that time we will also have a record of 
the additional costs incurred and reduced generation in FY 1993 as a 
result of flood mitigation accomplished by reduced water releases from 
the dams on the Pick-Sloan Missouri Basin System. We believe it is 
premature to revise only the generation projections without considering 
all impacts to the system. The generation projections in the 
ratesetting study correspond to the budget projections used in that 
study. The next year's PRS will consider all of these effects. At this 
time, it is our position that the additional costs incurred as a result 
of the flooding will offset the short-term benefits from nearly full 
reservoirs.
    Issue: Western should monitor actual losses on the transmission 
system and update the loss factors used in its PRS in the future.
    Response: We agree with this suggestion and will do this in the PRS 
for the next FY.
    Issue: Western should not use projected depletions beyond the cost 
evaluation period.
    Response: The position presented by the commenter points to the 
fact the Bureau and Corps recognize projections of stream-flow 
depletions which are unreliable. The quotes from the Bureau and the 
Corps have been taken out of context. The statements made by the Bureau 
and Corps are related to the short-term. During a drought, depletions 
are higher than forecast, and during wet years, depletions are lower 
than forecast. The long-term projections of depletions are based upon 
normal usage. If we accept long-term development of future projects, we 
must consider these depletions. Normal depletions would seem most 
reasonable. We do not agree that projection of depletions can be 
ignored when future projects are known to impact depletions.
    Issue: Western should revise its other revenue projections in the 
PRS to include additional revenues.
    Response: The commenters pointed to three areas where they saw a 
possibility of change:
    1. Second-year revenues--The commenter had questioned the reduction 
of special sales by approximately $7.5 million and the increased 
Western Division transmission revenues of $1.7 million in the second-
year revenue projections.
    The reduction of special sales revenues is an estimate based upon 
the impact of reduced generation in the second year, which was an 
expectation at the time of the estimate. Western feels it's appropriate 
to leave the estimated projection. The second item is the projected 
Western Division transmission revenue increases expected from the 
proposed rate adjustment. We agree with this in principle; however, if 
the rate adjustment is implemented as proposed, it has no significant 
impact on the overall rate adjustment. It would reduce only the first 
step of the rate adjustment by a few hundredths of a mill/kWh. Western 
is not proposing to make the change for this rate adjustment; however, 
in the future, when a transmission rate adjustment is being proposed at 
the same time as a firm power rate adjustment, we will reflect proposed 
changes in transmission revenues on a prospective basis rather than 
after the fact.
    2. Irrigation pumping rate--The commenter suggested that Western 
should actively encourage Reclamation to promptly complete the studies 
which could lead to a revision of the project-use pumping rates.
    Western has been in contact with Reclamation concerning the 
revision of their project-use rate. They have budgeted funds in FY 1994 
to perform the ``ability to pay studies'' for their irrigation pumping 
customers. We have provided study data which could define the rate 
required to cover O&M and annual replacement expenses associated with 
the power system. Western will continue to actively pursue this issue 
with Reclamation.
    3. Revenue from monthly sales over 60-percent load factor--The 
future revenues from the ``tiered'' energy rate are not reflected in 
the PRS. This is correct; however, the expense for purchasing this 
energy is also not projected in the PRS. If Western were to project the 
revenue for the monthly sales over 60-percent load factor, we would 
need to project offsetting purchased power costs. Therefore, adding 
these elements to the PRS is not rate impacting. We propose not to add 
the elements to the current ratesetting study but to add them to future 
PRSs for display purposes.
    Issue: Western should project future interest rates in the PRS 
instead of using the current-year rate for all future years.
    Response: Western uses the rate required by DOE Order RA 6120.2, 
sections 10.i. and 11.b., for all future investments. Section 10.i. 
states that forecasts for PRSs will utilize the rate for the latest 
available year established by the Secretary of the Treasury and that 
this rate shall be used for all future years. Section 11.b. defines the 
criteria used by the Department of the Treasury to determine the rate 
each year.
    The present rate is computed on the basis of interest-bearing 
Treasury securities which, at the time the computation is made, have 
terms of 15 years or more to maturity. On this basis, short-term 
fluctuations in market prices are removed and projections have built-in 
stability based upon a ``rolling average'' each year. In effect, 
volatile changes in the rate are mitigated through the blending 
process.
    While it is true that the interest rate may decrease in the FY 1994 
PRS, estimating a new rate would be no more accurate than the current 
method for projecting investment rates 3 or 4 years into the future. In 
fact, if such estimates were used in the late 1970s, they would have 
resulted in higher revenue requirements. There is no assurance that 
this would not happen again in the future.
    Issue: Western should take an interest credit in the PRS for the 
net cash balance accrued during the year for interest expense that is 
not due and payable until yearend.
    Response: The method used to compute interest in the PRS conforms 
to DOE Order RA 6120.2, section 10.j., dated September 20, 1979, which 
requires that interest shall be the sum of 1 year's interest on the 
unpaid balance of each investment plus \1/2\ year's interest on new 
investment added and in-service during the year, and interest on 
deferred annual expenses (i.e., capitalized deficits). This amount may 
be offset by a credit against interest expense if the credit concept is 
utilized by the power marketing agency.
    The methodology for computing the interest offset varies between 
PMAs; DOE Order RA 6120.2 does not prescribe a specific procedure to be 
used in making the interest calculation. The methodology employed by 
Western incorporates an interest credit for \1/2\ year on all principal 
payments made to investments during the current FY, and computes this 
credit at the same rates of the investments being repaid. No interest 
credit is taken for interest collected and retained throughout the 
year.
    This methodology is based on the premise that interest expenses are 
equivalent to annual operating expenses such as O&M and are due and 
payable throughout the year, not on the last day of the FY. As such, 
payments to the Department of the Treasury are made to repay interest 
as it is incurred. This approach is recommended by the U.S. General 
Accounting Office (GAO) in attachment 3 to a letter from DOE to the 
Administrators of the five PMAs dated September 8, 1983.
    In attachment 3, GAO reviewed the interest rate practices of four 
PMAs (Bonneville Power Administration, Southwestern Power 
Administration, Western Area Power Administration, and Southeastern 
Power Administration) and provided a draft recommendation that DOE 
revise DOE Order RA 6120.2 to incorporate Western's methodology for 
computing interest credits. GAO summarized that Western was utilizing 
reasonable business principles in the application of the interest 
credit.
    Western believes that the methodology employed by the P-SMBP and 
Fry-Ark PRSs is consistent with sound business principles and offers a 
fair and reasonable credit against interest expenses.

Environmental Evaluation

    In compliance with the National Environmental Policy Act of 1969, 
42 U.S.C. 4321 et seq.; Council on Environmental Quality Regulations 
(40 CFR parts 1500-1508); and DOE NEPA Regulations (10 CFR part 1021), 
Western has determined that this action is categorically excluded from 
the preparation of an environmental assessment or an environmental 
impact statement.

Executive Order 12866

    DOE has determined that this is not a significant regulatory action 
because it does not meet the criteria of Executive Order 12866, 58 FR 
51735. 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.

Availability of Information

    Information regarding these rate adjustments, including PRSs, 
comments, letters, memorandums, and other supporting material made or 
kept by Western for the purpose of developing the power rates, is 
available for public review in the Billings Area Office, Western Area 
Power Administration, Division of Market Studies, Rates and Resources, 
2525 4th Avenue North, Billings, Montana 59107-5800, telephone (406) 
657-6488; Western Area Power Administration, Division of Marketing and 
Rates, 1627 Cole Boulevard, Golden, Colorado 80401; and Western Area 
Power Administration, Office of the Assistant Administrator for 
Washington Liaison, room 8G-061, Forrestal Building, 1000 Independence 
Avenue SW., Washington, DC 20585.

Submission to Federal Energy Regulatory Commission

    The rates herein confirmed, approved, and placed into effect on an 
interim basis, together with supporting documents, will be promptly 
submitted to FERC for confirmation and approval on a final basis.

Order

    In view of the foregoing and pursuant to the authority delegated to 
me by the Secretary of Energy, I confirm and approve on an interim 
basis, effective the first day of the first full billing period 
beginning on or after February 1, 1994, Rate Schedules P-SED-F6 and P-
SED-FP6 for the Pick-Sloan Missouri Basin Program-Eastern Division. The 
rate schedules shall remain in effect on an interim basis, pending 
Federal Energy Regulatory Commission confirmation and approval of them 
or substitute rates on a final basis, through January 31, 1999.

    Issued in Washington, D.C., January 6, 1994.
Bill Whiten,
Deputy Secretary.

United States Department of Energy--Western Area Power 
Administration

[Schedule P-SED-F6 (Supersedes Schedule P-SED-F5)]

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 February 1, 1994, through September 30, 
1994.
    Second Step: Beginning on the first day of the first full billing 
period beginning on or after October 1, 1994, through January 31, 1999.
    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 Rate:
    First Step:
    Demand Charge: $3.00 for each kilowatt per month (kW-month) of 
billing demand.
    Energy Charge: 7.76 mills for each kilowatthour (kWh) for all 
energy delivered as firm power service. An additional charge of 3.38 
mills per kWh (mills/kWh), for a total of 11.14 mills/kWh, will be 
assessed for all energy delivered as firm power service that is in 
excess of 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: $3.20 for each kW-month of billing demand.
    Energy Charge: 8.32 mills for each kWh for all energy delivered as 
firm power service. An additional charge of 3.38 mills/kWh for a total 
of 11.70 mills/kWh will be assessed for all energy delivered as firm 
power service that is in excess of 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.
    Adjustments:
    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 the United States to justify the discount. The determination 
of eligibility for receipt of the voltage discount shall be exclusively 
vested in the United States.
    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.

United States Department of Energy--Western Area Power 
Administration

[Schedule P-SED-FP6 (Supersedes Schedule P-SED-FP5)]

Pick-Sloan Missouri Basin Program--Eastern Division, Montana, North 
Dakota, South Dakota, Minnesota, Iowa, Nebraska; Schedule of Rates for 
Firm Peaking Power Service

    Effective: First Step: The first day of the first full billing 
period beginning on or after February 1, 1994, through September 30, 
1994.
    Second Step: Beginning on the first day of the first full billing 
period beginning on or after October 1, 1994, through January 31, 1999.
    Available: To the customers of the Billings Area Office 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 Rate: 
    First Step:
    Demand Charge: $3.00 for each kilowatt per month (kW-month) of the 
effective contract rate of delivery for peaking power or the maximum 
amount scheduled, whichever is greater.
    Energy Charge: 7.76 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: $3.20 for each kW-month of the effective contract 
rate of delivery for peaking power or the maximum amount scheduled, 
whichever is greater.
    Energy Charge: 8.32 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.
    Adjustments:
    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. 94-1487 Filed 1-19-94; 4:15 pm]
BILLING CODE 6450-01-P