[Federal Register Volume 59, Number 212 (Thursday, November 3, 1994)]
[Unknown Section]
[Page 0]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 94-27306]


[[Page Unknown]]

[Federal Register: November 3, 1994]


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DEPARTMENT OF ENERGY
Western Area Power Administration

 

Salt Lake City Area/Integrated Projects Notice of Rate Order No. 
WAPA-63

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of Rate Order''Salt Lake City Area/Integrated Projects 
(Integrated Projects) 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-63 
and Rate Schedule SLIP-F5 placing firm power rates for capacity and 
energy from the Integrated Projects of the Western Area Power 
Administration (Western) into effect on an interim basis. 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.
    The provisional firm power rates to be effective from December 1, 
1994, through November 30, 1999, consist of an energy charge of 8.90 
mills per kilowatthour (mills/kWh) and a capacity charge of $3.83 per 
kilowatt month (kW-month), which result in a composite rate of 20.17 
mills/kWh. This is a 7.9-percent increase over the current energy 
charge of 8.40 mills/kWh and the current capacity charge of $3.54/kW-
month which results in a composite rate of 18.70 mills/kWh. A 
comparison of existing and provisional rates follows: 

   Salt Lake City Area/Integrated Projects Comparison of Existing and   
                      Provisional Firm Power Rates                      
------------------------------------------------------------------------
                                               Existing     Provisional 
                                                rates          rates    
                                            (effective 10/ (effective 12/
                                                 92)            94)     
------------------------------------------------------------------------
Firm Power Service Rate Schedule..........  SLIP-F4        SLIP-F5      
Firm Capacity Charge ($/kW/month).........  $3.54          $3.83        
Firm Energy Charge (mills/kWh)............  8.40           8.90         
Composite Rate (mills/kWh)................  \1\18.70       20.17        
------------------------------------------------------------------------
\1\The rates calculated at a 58.2-percent load factor can be expressed  
  as a Combined Rate of 16.72 mills/kWh.                                

DATES: Rate Schedule SLIP-F5 will be placed into effect on an interim 
basis on the first day of the first full billing period beginning on/or 
after December 1, 1994, and will be in effect until FERC confirms, 
approves, and places the rate schedule in effect on a final basis 
through November 30, 1999, or until the rate schedule is superseded.

FOR FURTHER INFORMATION CONTACT:

Mr. Kenneth G. Maxey, Area Manager, Salt Lake City Area Office, Western 
Area Power Administration, 275 East 200 South, Suite 475, Salt Lake 
City, UT 84111, (801) 524-6372
Ms. Deborah M. Linke, Chief, Rates and Statistics Branch, Western Area 
Power Administration, P.O. Box 3402, Golden, CO 80401-0098, (303) 275-
1618
Mr. Joel Bladow, Assistant Administrator for Washington Liaison, 
Western Area Power Administration, Room 8G-027, 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 (Secretary) delegated (1) the authority to develop long-term 
power and transmission rates on a nonexclusive basis to the 
Administrator of Western; (2) the authority to confirm, approve, and 
place such rates into effect on an interim basis to the Deputy 
Secretary; 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.
    The main issues raised at public meetings and in written comments 
included (1) cost projections used in the Power Repayment Study (PRS), 
(2) water depletion schedules assumed for future power projections, and 
(3) estimated future prices for purchased power. Western has considered 
all comments in preparation of the provisional rates.
    Rate Order No. WAPA-63, confirming, approving, and placing the 
proposed Integrated Projects rate adjustment into effect on an interim 
basis, is issued, and the new Rate Schedule SLIP-F5 will be promptly 
submitted to FERC for confirmation and approval on a final basis.

    Issued in Washington, D.C. October 24, 1994.
William H. White,
Deputy Secretary.

Order Confirming, Approving, and Placing the Salt Lake City Area/
Integrated Projects Firm Power Service Rates Into Effect on an Interim 
Basis

    In the Matter of Western Area Power Administration Rate 
Adjustment for Salt Lake City Area/Integrated Projects
October 24, 1994.
[Rate Order No. WAPA-63]
    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 project system involved, were transferred to and 
vested in the Secretary of Energy (Secretary).
    By Amendment No. 3 to Delegation Order No. 0204-108, published 
November 10, 1993 (58 FR 59716), the Secretary 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 the 
Federal Energy Regulatory Commission (FERC). 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 (i.e., $ per kilowatt (kW) 
per month).
    AF: Acre-foot. The amount of water necessary to cover 1 acre of 
land to a depth of 1 foot.
    Basin Fund: That account in the U.S. Department of the Treasury, 
established by the Colorado River Storage Project (CRSP) Act.
    Billing Demand: The greater of (1) the highest 30-minute 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.
    Capacity Component: Part of a firm power rate; shown in the power 
repayment study (PRS) as a dollar per kW per year charge. Billed on a 
dollar per kW per month basis. Applied each billing period to each kW 
which each contractor is entitled by contract.
    Categorical Exclusion: Characterizes an action which does not 
individually or cumulatively have a significant effect on the human 
environment and which has been found to have no such effect in 
procedures adopted by a Federal agency and for which, therefore, 
neither an environmental assessment nor an environmental impact 
statement is required.
    CME: Capitalized movable equipment.
    Collbran: Collbran Project.
    CREDA: Colorado River Energy Distributors Association.
    CROD: Contract rate of delivery. Capacity the supplier of electric 
service agrees to have available for delivery. It may or may not be 
accompanied by energy.
    CRSM: Colorado River Simulation Model.
    CRSP: Colorado River Storage Project.
    CRSP Act: Act of April 11, 1956, ch. 203, 70 Stat. 105, as amended, 
43 U.S.C. 620-620o.
    CWIP: Construction work in progress.
    Customer Brochure: A document prepared for public distribution 
explaining the background of the rate proposal.
    Demand: The rate at which electric capacity is delivered to or by a 
system over any designated period of time.
    DOE: U.S. Department of Energy.
    DOE Order RA 6120.2: An order dealing with power marketing 
administration financial reporting.
    EA: Environmental assessment.
    EIS: Environmental impact statement.
    Energy Component: Part of a firm power rate; expressed in mills per 
kilowatthour (kWh). Applied to each kWh made available to each 
customer.
    Exception Criteria: An agreement between Reclamation and Western 
setting forth conditions for operating the Glen Canyon Dam outside of 
test flows and subsequent interim operating criteria, including system 
regulation, emergency situations, and for the specific purpose of 
avoiding high-cost replacement power purchases.
    FERC: Federal Energy Regulatory Commission.
    FPOD: Federal point of delivery.
    FY: Fiscal year.
    Glen Canyon Dam: The dam on the Colorado River which forms Lake 
Powell.
    Glen Canyon Dam EIS: Glen Canyon Dam Environmental Impact 
Statement.
    GCPA: Grand Canyon Protection Act of 1992.
    IDC: Interest during construction.
    Integrated Projects: The Salt Lake City Area/Integrated Projects, 
which encompass the combined sales and resources of the CRSP, Collbran, 
and Rio Grande Projects.
    Interior: U.S. Department of the Interior.
    kW: Kilowatt; 1,000 watts.
    kWh: Kilowatthour; the common unit of electric energy, equal to one 
kW taken for a period of 1 hour.
    Load: The amount of capacity or energy delivered or required at any 
specified point or points on a system. Load originates primarily with a 
customer's energy-consuming equipment.
    M&I: Municipal and industrial.
    Mill: Unit of monetary value equal to .001 of a U.S. dollar; i.e., 
1/10th of a cent. Used to express wholesale energy and composite 
electric rates.
    Mills/kWh: Mills per kilowatthour.
    MW: Megawatt; 1,000 kW; 1,000,000 watts.
    NEPA: National Environmental Policy Act of 1969.
    OMB: Office of Management and Budget.
    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 some 
future year to meet relatively large annual costs or to repay 
investments which come due.
    PMA: Power marketing administration.
    PRS: Power repayment study.
    Reclamation: Bureau of Reclamation, U.S. Department of the 
Interior.
    Regional Office: Bureau of Reclamation's Regional Office.
    RGP: Rio Grande Project.
    SLCA: Salt Lake City Area.
    SLCAO: Salt Lake City Area Office.
    Upper Basin States: Colorado, New Mexico, Utah, and Wyoming.
    UCRC: Upper Colorado River Commission.
    Watt: The electrical unit of power or rate of doing work. It is 
analogous to horsepower or foot-pounds per minute of mechanical power. 
One horsepower is equivalent to approximately 746 watts.
    Western: Western Area Power Administration, U.S. Department of 
Energy.
    WSCC: Western Systems Coordinating Council.

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 
December 1, 1994, and will be in effect pending FERC's approval of them 
or substitute rates on a final basis through November 30, 1999, 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 this firm power rate. The provisional 
firm power rate represents an increase of more than 1 percent in total 
Integrated Projects revenues; therefore, it is a major rate adjustment 
as defined at 10 CFR Secs. 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. A preliminary Federal Register notice (FRN), published July 1, 
1993 (58 FR 35449), invited interested parties to participate in the 
determination of whether an Integrated Projects' firm power rate 
increase was necessary. Western also invited participation in deciding 
the issues that should be addressed in the process.
    2. Several informal meetings were held between the publication of 
the July 1, 1993, FRN and the beginning of the public rate adjustment 
process. These meetings, involving personnel from Western, Reclamation, 
and represen- tatives from organizations of interested parties, 
produced many issue papers that identified and discussed the items 
which should be considered in a firm power rate adjustment. Agreement 
as to how to approach many of the issues was reached during this time, 
considerably reducing the number of unresolved issues and easing the 
later formal public process.
    3. On December 27, 1993, letters were mailed from Western's 
Loveland, Phoenix, and Salt Lake City Area Offices to all Integrated 
Projects customers and other interested parties announcing an informal 
public meeting to be held on January 31, 1994.
    4. At the informal meeting held on January 31, 1994, Western and 
Reclamation representatives explained the need for a rate increase and 
answered questions.
    5. An FRN was published on April 21, 1994 (59 FR 19008), officially 
announc- ing the proposed firm-power rate adjustment, initiating the 
public consultation and comment period, announcing the public 
information and public comment forums, and presenting procedures for 
public participation.
    6. On April 22, 1994, a rate announcement package was mailed from 
Western's Salt Lake City Area Office to all Integrated Projects 
customers and other interested parties announcing the publication of 
the FRN of April 21, 1994, and the beginning of the formal public 
process to adjust firm power rates. The package contained (1) a letter 
announcing the upcoming public information and comment forums, (2) a 
copy of the April 21 FRN, and (3) a copy of the April 1994 Integrated 
Projects Firm Power Rate Adjustment brochure. Rate announcement 
packages were mailed to customers served by Western's Loveland and 
Phoenix Area Offices on April 25, 1994.
    7. At the public information forum held on May 24, 1994, Western 
and Reclamation representatives explained the need for the rate 
increase in greater detail and answered questions.
    8. The comment forum was held on June 30, 1994, to give the public 
an opportunity to comment for the record. Four persons representing 
customers and customer groups made oral comments.
    9. Nine comment letters were received during the 97-day 
consultation and comment period. The consultation and comment period 
was originally scheduled to end on July 20, 1994. A letter was sent to 
all interested parties from the SLCAO on July 19, 1994, stating that 
Western would continue to accept written comments through July 27, 
1994. Letters were mailed from the Loveland and Phoenix Area Offices on 
July 20, 1994. All comments submitted by the end of the comment period 
have been considered in the preparation of this rate order.

Project History

    The Integrated Projects consist of the CRSP and the Rio Grande and 
Collbran Projects. The projects were integrated for marketing and 
ratemaking purposes on October 1, 1987. The goals of integration were 
to increase marketable resources, simplify contract and rate 
development and project administration, assure repayment of Collbran 
and Rio Grande Projects' costs, and create a common rate. The projects 
maintain their individual identities for financial accounting and 
repayment purposes, but their revenue requirements are integrated into 
one PRS for ratemaking.

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 power. Repayment criteria are based on law, policies, 
authorizing legislation, and DOE Order RA 6120.2.

Existing and Provisional Rates

    A comparison of the existing and provisional rates follows:

   Salt Lake City Area Integrated Projects Comparison of Existing and   
                      Provisional Firm Power Rates                      
------------------------------------------------------------------------
                                               Existing     Provisional 
                                                rates          rates    
                                            (effective 10/ (effective 12/
                                                 92)            94)     
------------------------------------------------------------------------
Firm power service rate schedule..........  SLIP-F4        SLIP-F5      
Firm capacity charge ($/kW/month).........  $3.54          $3.83        
Firm energy charge (mills/kWh)............  8.40           8.90         
Composite rate (mills/kWh)................  18.70\1\       20.17        
------------------------------------------------------------------------
\1\The rates calculated at a 58.2-percent load factor can be expressed  
  as a combined rate of 16.72 mills/kWh.                                

Certification of Rate

    Western's Administrator has certified that the Integrated Projects 
firm power rate placed into effect on an interim basis herein is the 
lowest possible consistent with sound business principles. The rate has 
been developed in accordance with agency administrative policies and 
applicable laws.

Discussion

    Many factors influenced this rate adjustment. The items having an 
impact upon the proposed Integrated Projects firm power rates are 
summarized in the table below. Because rates must earn sufficient 
revenues to pay for estimated future costs, the table compares the 
change in the average annual projections used in the FY 1991 Rate Order 
PRS (which set the rate effective October 1, 1992) and the ratesetting 
PRS prepared for this rate adjustment. 

    Major Factors Affecting the Integrated Projects' Firm Power Rate    
------------------------------------------------------------------------
                                                Change in               
                                                 average                
                                                 annual       Estimated 
                   Event                         revenue     rate effect
                                               requirement   (mills/kWh)
                                               ($000,000)               
------------------------------------------------------------------------
Increase in Colorado River Storage Project                              
 (CRSP) Transmission and Other Miscellaneous                            
 Revenues: primarily, compensation for new                              
 Phase-Shifter services (for Western System                             
 Coordinating Council loop-flow mitigation).         $-2.6         -0.33
Increase in CRSP Operation & Maintenance                                
 (O&M) Expense: $2.8 million per year due to                            
 inclusion of CME interest (inadvertently                               
 omitted from current rate); Remainder due                              
 to shifting of field crews from                                        
 construction to maintenance work...........           8.2          1.05
Increase in Small Project O&M Expense: Rio                              
 Grande Project is one of Western's oldest                              
 projects, and O&M increases with age;                                  
 Collbran has many small irrigation dams                                
 needing repair.............................           1.1          0.14
Increase in Purchased Power and Transmission                            
 Expense: The environmentally-related flow                              
 restrictions already in place at CRSP                                  
 powerplants require Western to purchase                                
 additional power to meet contractual                                   
 delivery obligations.......................           1.6          0.20
$51.2 million in historical environmental                               
 expenses made nonreimbursable by Grand                                 
 Canyon Protection Act (plus $9.1 million                               
 associated with deferred interest expense);                            
 Applied to outstanding deficits............          -0.5         -0.06
Passage of Grand Canyon Protection Act made                             
 certain future environmental costs                                     
 nonreimbursable............................          -1.0         -0.13
Increase in Interest on Project Investment:                             
 The increase in power investment and unpaid                            
 deficits since the October 1992 rate                                   
 adjustment resulted in an increase in                                  
 annual interest due........................           2.1          0.27
Increase in Project Additions and                                       
 Replacements: As noted on page 13 of Rate                              
 Brochure, $80.5 million was omitted from                               
 CWIP in the October 1992 rate adjustment...           1.2          0.15
Increase in aid to CRSP irrigation and                                  
 participating projects: Investment is very                             
 similar to October 1992 rate adjustment;                               
 however, there are 63 total years to pay                               
 for the investment, rather than the 65                                 
 years used previously since both studies                               
 have the pinch-point year of 2057. The                                 
 change in the divisor results in the annual                            
 increase...................................           1.4          0.18
                                             ---------------------------
    Totals..................................         $11.5          1.47
------------------------------------------------------------------------

    The existing and proposed revenue requirements for the Integrated 
Projects are as follows: 

   Integrated Projects Average Annual Firm-Power Revenue Requirements   
------------------------------------------------------------------------
                                                     Estimated average  
                                                  annual FY 1995-99 firm
                                                   power revenue ($000) 
                                                 -----------------------
                                                    SLIP-F4     SLIP-F5 
------------------------------------------------------------------------
Firm power revenue..............................  \1\$109,26            
                                                           5  \2\$122,41
                                                                       3
------------------------------------------------------------------------
\1\From FY 1991 Rate Order PRS.                                         
\2\From Ratesetting PRS.                                                

    The rate increase is necessary to satisfy the cost-recovery 
criteria set forth in DOE Order No. RA 6120.2. This rate schedule, 
which will be effective on an interim basis beginning December 1, 1994, 
replaces Rate Schedule SLIP/F4 which FERC approved through September 
30, 1996 at 62 FERC 61,159 (February 18, 1993).

Statement of Revenue and Related Expenses

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

Salt Lake City Area/Integrated Projects Comparison of 5-Year Rate Period
                     Revenues and Expenses ($1,000)                     
------------------------------------------------------------------------
                                 Ratesetting  FY 1991 rate              
           Revenues               PRS 1995-     order PRS    Difference 
                                    1999       1995-1999                
------------------------------------------------------------------------
Revenue Distribution:                                                   
  O&M.........................      $237,483      $218,540       $18,943
  Environmental...............        19,295        37,223       -17,928
  Net purchased power\2\......           972        -1,953         2,925
  Transmission................        35,785        31,695         4,090
  Interest....................       229,029       188,103        40,926
  Miscellaneous expenses\3\...        45,976        20,430        25,546
  Investment repayment........       102,255        99,189         3,066
                               -----------------------------------------
    Total\4\..................    \1\670,795    \5\593,227    \6\77,568 
------------------------------------------------------------------------
\1\To be comparable with the FY 1991 Rate order PRS, the ratesetting    
  PRS' ``Other Miscellaneous Revenues'' (from sales of surplus off-peak 
  energy) were deducted from the total revenues and were combined with  
  total purchased power expense.                                        
\2\Net Purchased Power Expenses (Ibid.). Negative net purchase power    
  expense figures imply surplus sales in excess of total purchase power 
  expenses. Likewise, positive net purchase power expense figures imply 
  total purchase power expenses in excess of total power sales.         
\3\Interest on undepreciated CME, annual liability for the Civil Service
  Retirement System, and annual gross power-related requirements for the
  Collbran, Provo River, Rio Grande, and Seedskadee Projects.           
\4\Includes repayment of capitalized deficits.                          
\5\Does not equal Total Revenues due to rounding.                       
\6\Ibid.                                                                

Basis for Rate Development

    The provisional Integrated Projects rate was designed to continue 
to maintain an approximate 50/50 split between revenue earned from 
demand charges and that earned from energy charges. The cost to 
individual customers will vary because of differences in the amounts of 
capacity and energy they purchase from the Integrated Projects.
    The provisional rate contains a $3.83/kW/month firm-capacity charge 
and an 8.90 mills/kWh firm-energy charge in FY 1995. The necessary 
composite rate is 20.17 mills/kWh, which is an increase of 7.9 percent 
above the existing rate. The rate terminates on November 30, 1999.

Comments

    During the 97-day comment period, Western received nine letters 
commenting on the rate adjustment. One letter was received after the 
close of the comment period. Additionally, four persons commented 
during the June 30, 1994, public comment forum. All comments received 
by the end of the comment period were reviewed and considered in the 
preparation of this rate order. Written comments were received before 
the comment deadline from the following sources:

Bountiful City Light and Power (Utah)
Bridger Valley Electric Association (Wyoming)
Colorado River Energy Distributors Association (Arizona, Colorado, 
Nevada, New Mexico, Utah, and Wyoming)
Energy Strategies, Inc. (Utah)
Garkane Power Association, Inc. (Arizona and Utah)
Intermountain Consumer Power Association (Nevada and Utah)
Irrigation and Electrical Districts Association of Arizona (Arizona)
Upper Colorado River Commission (Colorado, New Mexico, Utah, and 
Wyoming)
Utah Municipal Power Agency (Utah)

    Representatives of the following organizations made oral comments:

    Colorado River Energy Distributors Association (Arizona, 
Colorado, Nevada, New Mexico, Utah, and Wyoming)
    Intermountain Consumer Power Association (Nevada and Utah)
    Irrigation and Electrical Districts Association of Arizona 
(Arizona)
    Platte River Power Authority (Colorado)

    Most of the comments received at the public meetings and in 
correspondence dealt with cost, purchased power, and water depletion 
projections.
    The comments and responses, paraphrased for brevity when it does 
not affect the meaning of the statement(s), are discussed below. Direct 
quotes from comment letters are used for clarification where necessary.
    The issues discussed are: (1) Depletion-related issues, (2) 
purchased power expense, (3) future flow restrictions at Glen Canyon 
Dam, (4) O&M-related issues, (5) construction-related projections, (6) 
environmentally-related expenses, (7) miscellaneous comments, and (8) 
issue paper resolution.
1. Depletion-Related Issues
    Extensive comments were made regarding the deferred recognition of 
water depletions for water projects in the Colorado River Basin after 
FY 2010. Western's responses are listed sequentially:
    a. Comment: Western is being guided solely by RA 6120.2 in the 
rate-setting process without paying sufficient attention to the CRSP 
Act of 1956 and other relevant legislation. The rate does not 
accurately reflect the intent of the CRSP Act, which is to produce 
rates that result in full repayment of the power system costs.
    Response: Western disagrees. Western complies with requirements of 
the CRSP Act of 1956, other relevant legislation, and DOE Order RA 
6120.2 in assuring repayment of all CRSP costs assigned to power. 
Legislation takes precedence when there is conflict with DOE Order RA 
6120.2.
    Treatment of depletions in the same manner has been approved by 
FERC twice prior to the present rate adjustment. Two of FERC's criteria 
for rate approval are whether the proposed rate will repay all 
obligations assigned to power in full and on time consistent with 
requirements of the CRSP Act and whether the methodology which achieves 
this result is in compliance with DOE Order RA 6120.2. The requested FY 
1995 rate adjustment meets these criteria and satisfies all repayment 
requirements.
    b. Comment: If power rates are set without providing for future 
depletions, it will affect Upper Basin development under the (Colorado 
River and Upper Colorado River Basin) compacts. Every time someone 
wants to build a project or open a business that will deplete water, 
the power rates will have to go up if those increased depletions have 
not already been factored into the rates.
    Can full repayment be truly represented by rates derived assuming 
water is available for release through powerplants when that water will 
not be available because of depletions by the Upper Division States 
above the powerplants?
    Response: Total depletions forecasted by the Basin States for the 
use of Colorado River water have been included in the proposed rate. 
The water has been allocated by compacts for use by the Upper Basin 
States. Furthermore, Western is obligated to assure that funds are 
available on schedule to meet repayment requirements regardless of 
depletion schedules.
    In its proposed treatment (deferral) of uncertain depletions, 
Western assumes that greater amounts of Colorado River water will be 
available for release through CRSP powerplants than would be suggested 
by current rapid-growth forecasts of water development projects and 
their associated depletions.
    Western's experience has been that out-year depletion estimates are 
subject to frequent revision. It is reasonable, therefore, to give more 
weight to near-term projections. Western prepares an annual PRS for 
every project to assure that repayment is proceeding satisfacto- rily. 
Thus, there will be many future opportunities to revise the Integrated 
Projects rate appropriately as the near-term projections are changed 
and more accurate long-term estimates are made available.
    Western has determined that depletions affect the firm power rate, 
at most, by 0.32 mills/kWh (composite). The impact is small enough so 
that power rates could (and would) be adjusted to assure full 
repayment, if more rapid depletions take place in the Upper Basin 
States. It is not likely that this small impact on power rates would 
constrain water depletions.
    c. Comment: By its own terms the 1983 Agreement between Reclamation 
and Western does not apply to State and private projects or 
developments and that the agreement reveals the parties' intent to use 
full depletion levels in setting rates under the terms of the 
Agreement.
    Response: Western disagrees that the intent of the 1983 Agreement 
was for Western to use ``full'' (or ultimate) depletion levels in 
setting rates. Rather, a provision of the agreement that addresses 
depletions only requires that water depletion schedules used for power 
repayment studies ``. . . be consistent with construction schedules for 
participating projects.''
    Western agrees that provisions of the 1983 Agreement between 
Western and Reclamation did not explicitly address State and private 
projects or developments. In defining a ``reasonable expectation 
standard,'' the 1983 Agreement establishes necessary steps by 
Reclamation to demonstrate the potential for construction of future 
Federal participating projects before the costs of these projects would 
be included in the ratesetting years. This reasonable expectation 
standard has been applied to the future development of all water 
development projects for ratesetting purposes by Western in setting the 
lowest possible rates consistent with sound business principles.
    Therefore, Western has included total depletions forecasted by the 
Upper Basin States for the use of Colorado River water for all 
projects, with deferral of less-certain water developments (depletions) 
beyond the ratesetting period in the proposed rate. Future rate 
adjustments will allow for movement of depletions into the rate- 
setting years.
    d. Comment: Western arbitrarily suppressed depletions from 2010 
through 2090 only justified by the fact that such a method of 
suppression (capping) was utilized in the 1990 study and did so without 
adequate consultation with Reclamation.
    Response: The decision by Western to defer uncertain depletions 
beyond the ratesetting period is not arbitrary. In the 1990 rate 
process, Western gave considerable attention to the reasonableness of 
the then-proposed depletion deferral and to the associated rate effect 
when applied. Further, Western has given renewed and height- ened 
attention to the treatment of depletions in the proposed rate through 
preparation of numerous issue papers, informal discussions with both 
customer and water user representatives, and in Western's April 1994 
rate brochure.
    Figure 1, on page 12-5 of the rate brochure, shows that Western 
presently assumes full development (full depletions) of all Upper Basin 
water projects by FY 2090.
    Projects with uncertain schedules have been placed in the PRS so 
that they do not impact the rate at this time, in accordance with 
Western's practice to set the lowest possible rate consistent with 
sound business principles.
    Western also disagrees with the claim that inadequate consultation 
occurred with Reclamation in the past on this deferral treatment. 
Reclamation, along with other interested parties, has either 
participated in or has attended many of the public forums scheduled in 
the development of all Integrated Projects rate proposals. In these 
public forums, Western has detailed the components of the rate 
adjustment, including the treatment of depletions. Reclamation and 
interested parties have been and will continue to be afforded ample 
notice and opportunity to comment on future rate proposals.
    e. Comment: Five comments said: DOE RA 6120.2 seems to require the 
use of operation studies based on historical streamflows including 
hydrologic data current to within 5 years.
    Response: Western believes that it is in compliance with DOE RA 
6120.2. This requirement is valid for most projects. However, 
exceptions, as discussed in DOE RA 6120.2, Section 10.e.(4), are 
provided for those projects which are anticipated to have extensive 
water development in the future. CRSP operation studies are based on 
historic streamflows, which are then reduced by projected water 
depletions supplied by the Upper Basin States and modified by 
Reclamation.
    f. Comment: Western suggests that its departure from the 1990 
depletion schedule represents better data than utilized by Reclamation 
in its energy and capacity studies.
    Response: Both Reclamation and UCRC staff have told Western infor- 
mally that the depletion schedule used in this process is a more 
accurate reflection of the current situation than the earlier ``Energy 
and Capacity Studies'' which was available when the ratesetting PRS was 
prepared.
    g. Comment: The 1990 cap at 2010 resulted in an approximate 11-
percent reduction of Basin States' depletions and an artificially low 
power rate. The proposed super-imposition of a 1990 mentality beginning 
in 2010 to a substantially revised 1992 unofficial depletion schedule 
results in excess of 20-percent reduction of depletions and does not 
even fully recognize the future depletions of projects currently under 
construction.
    Response: Western agrees that the deferral of some estimated deple- 
tion effects until 2060 suggests a significant (20-percent) reduction 
from the 1992 depletion schedule contained in the CRSM demand data. 
Western believes there should be greater certainty of development 
regarding this 20-percent prior to including the associated reduction 
in hydrogeneration in the PRS in a way that affects the firm power 
rates. Also, Western agrees that its deferral postpones future 
depletions of projects currently under construction, based on the 
principles of the 1983 agreement. Again, because the timing of the 
development of the associated consumptive use is uncertain, Western 
chooses to not include future depletions within the ratesetting years. 
As more current information is supplied by the UCRC to Reclamation, 
Western will apply the ``reasonable expectation'' standard to these 
updated depletions.
    h. Comment: Western did not use the depletion schedule dated July 
1994 which was received in draft form in April 1994.
    Response: Western was provided a draft work-in-progress depletion 
schedule by UCRC representatives in April 1994. This latest unofficial 
schedule demonstrated a reduced and delayed schedule for development of 
Upper Basin projects. However, the schedule had yet to be approved by 
the Basin States and, once received by Reclamation, would still have 
required considerable work by Reclamation staff to modify depletion 
(demand) data used by the CRSM. In addition, subsequent analysis by 
Western's power resources and rates staff would have taken considerable 
time and effort before new information could be verified and supported 
for inclusion in any revised PRS for this proposed rate process. For 
example, the final PRS used for the April 1994 rate brochure was 
created in March of 1994. Its power projections were the end result of 
several months of work by Western and Reclamation resources staff. An 
official depletion schedule ready for use in July of 1994 would have 
delayed the public process for the current rate adjustment by several 
additional months.
    Western is responsible for seeing that the Integrated Projects earn 
sufficient revenues to pay all of their obligations on time. Such a 
lengthy delay in implementing the rate adjustment would have resulted 
in increased interest cost to customers, lost revenues, and, as a 
result, higher firm power rates.
    Western has assured UCRC that when official depletion information 
is available, has been incorporated into Reclamation's CRSM data files, 
and there is a common understanding of the reasonable certainty of 
future water projects, the associated generation effects will be 
weighed and a decision made by Western regarding their inclusion in any 
future PRS.
    i. Comment: The attorney for a customer stated:
    . . . the treatment of depletions in this rate case has nothing to 
do with the water rights of the Upper Basin States. Nor does it have 
anything to do with how those rights will be exercised in the future. 
Western has no power over the water rights of the Upper Basin States. 
Conversely, the power users should not be punished because of delays in 
Upper Basin water use development and fears of Upper Basin water users 
that such development may ultimately not occur.
    Response: Western agrees with this comment.
2. Purchased Power Expense
    Four large customer organizations all commented extensively on 
purchased power expense:
    a. Comment: A customer organization stated:
    The assumed lower prices for surplus energy sales are, in fact, at 
odds with recent experience for the SLCA/IP.
    It is clear that experience does not support Western's pricing 
assumptions, which were based on combining various pricing and cost 
data in an inconsistent and somewhat arbitrary fashion. (The commentor) 
recommends that Western modify its pricing assumptions by setting 
prices for surplus sales at the same levels as those used for 
purchases.
    Response: Western agrees, in part, with comments that assumed 
nonfirm surplus sales pricing in the estimation of future-year net 
purchased power expenses does not reflect an extension of historic 
pricing trends. This fact is supported in documentation prepared by 
Western on the methodology and assumptions developed in previous rate 
proceedings and consistently applied again in this proposed rate 
adjustment. The imposed restrictions at Glen Canyon Dam have caused 
Western to sell off-peak surplus energy. The impact of these sales is 
based upon the market conditions. Western has explained that the basis 
for assumptions of future surplus sales pricing is based upon 
consideration of the potential market conditions. Western assumes that 
there will be a need to dispose of limited onpeak surpluses in southern 
markets, which will mean competing against low-cost sales from the 
Navajo Generating Station. Western will also try to sell significant 
surpluses in northern markets, competing against low-cost sales from 
regional northern utilities. Certain general conclusions may be drawn: 
(1) average nonfirm surplus energy prices, both offpeak and onpeak, 
will be less than historic conditions, this also implies that period 
pricing (onpeak or offpeak) will be less than recent experience, (2) 
historic pricing differentials, onpeak versus offpeak, winter versus 
summer season, will continue, and (3) Western's hourly modeling of 
constrained operations at Glen Canyon is reasonable.
    Though the method developed is believed to be a reasonable tool for 
forecasting future surplus sales pricing, Western acknowledges that 
some merit exists in comments that suggest a closer link to recent 
historic trends is reasonable. Western will continue to refine the 
methods for forecasting future market conditions, both purchases and 
surplus sales, and will continue to give greater weight to recent 
historic pricing trends in future pricing projections.
    Western disagrees with the comment which suggests that surplus 
sales and purchase pricing should be identical, without consideration 
of the nature of the constraint condition at Glen Canyon. The methods 
developed by Western for assessment of conditions with and without 
interim release constraints at Glen Canyon currently predict (a) that 
higher, but acceptable, average purchase prices will result in the near 
future from deliveries under several long-term purchase agreements and 
(b) lower average surplus sale prices will occur due to significant 
``forced sales'' during offpeak and shoulder onpeak hours. However, 
should additional operation experience suggest modification to this 
base assumption, Western will consider future improvements in the 
methods used.
    b. Comment: Western applied the hourly modeling of net purchased 
power expense to only 3 years. The other years between and beyond the 3 
years modeled were estimated based on a regression analysis of the 3 
years' results . . . regression analysis using three data points to 
interpolate and extrapolate results may be unreliable and is certainly 
less than ideal. (The commentor) recommends that the hourly model be 
used to calculate annual net expense at least through the year 2002, 
when the recovery of the hydrosystem and increases in firm load . . . 
have stabilized.
    Response: Western disagrees with the suggestion that additional 
years of hourly modeling in its current form would significantly 
improve the reliability of forecasted net purchase power expenses.
    The methodology developed by Western to forecast the net purchase 
power expense considers several significant variables such as hourly 
firm load and available hourly hydrogeneration in determination of 
hourly deficits or surpluses. The method then considers seasonal 
variation in purchase and surplus sales pricing structures in 
estimation of the net purchase power expense. Given the simplifying 
assumptions made in the methods, Western recognizes a significant 
correlation between deficit (or surplus) hydrogeneration and the 
associated net purchase power expense.
    In balancing the limited time required to complete the analysis and 
the precision required for the net expense estimate, Western determined 
that modeling all hours within each month for 3 years (i.e., 36 months) 
would be adequate and that hourly modeling for additional years would 
not significantly improve the reliability of the forecasted net 
purchase power expense.
    Western continues to support the general application of these 
methods to express the causal relationship between deficit (or surplus) 
hydrogeneration and annual net purchase power expenses. However, 
Western acknowledges that some future modifications may be beneficial, 
such as (1) additional refinements of the model, (2) validation of key 
assumptions, and (3) application of refined methods and assumptions to 
additional future periods (i.e., months, years) to increase the sample 
size. Such changes will be considered in future net purchase power 
expense forecasts.
    c. Comment: A large customer organization says that it has been 
unable to understand or replicate Western's results.
    Response: Western has made a conscientious effort to provide all of 
the information needed to develop the purchased power expense analysis 
in a timely manner. Western's staff has provided explanations to 
customers and their consultants and are available and willing to 
provide additional clarification as needed.
3. Future Flow Restrictions at Glen Canyon Dam
    a. Comment: A large customer organization expressed concern that 
Western has overstated revenues of $3 to $8 million per year from 
short-term capacity sales through 2004.
    Response: It is improbable that flows restricted for environmental 
reasons will ever again provide enough firm power from the Glen Canyon 
Unit to reach levels used in past power projections. Western does not 
know which of many possible flow regimes will finally be imposed at the 
Glen Canyon Unit. The treatment of short-term sales has been consistent 
with the firm power assumptions. Therefore, it is impossible to modify 
power projections for the proposed rate adjustment to recognize the 
reduced power output. The only course of action Western is able to 
follow is to stay with historic power projection figures, using the 
methodology already used in previous processes, until the Glen Canyon 
regime is finally determined.
    Western will evaluate the firm power rate then in place when the 
new flow regimes from the Glen Canyon Dam are decided. If it is needed, 
a firm power rate adjustment will be proposed then.
    b. Comment: An organization of several customers stated: While it 
is understood that a degree of uncertainty surrounds the exact level of 
flows at Glen Canyon, Western should conduct a sensitivity analysis 
predicated on the alternative flow assumptions identified in the 
Operation of Glen Canyon Dam Environmental Impact Statement. Such 
sensitivity analysis (sic) would give customers a range of possible 
replacement power costs.
    Response: Western has done extensive analyses of the power and rate 
impact of every flow regime identified for study in the GCD-EIS. 
Detailed descriptions of the studies and their results are reported in 
the draft GCD-EIS, and will be contained in the final GCD-EIS when it 
is published.
    In the meantime, Western is specifically required, by law and by 
regulation, to use known or statistically probable estimates of future 
activity in creating rates. The level of uncertainty still existing 
with the GCD-EIS prevents the use of any of its data at this time. As 
is noted above, when a decision about environmentally related flows 
through Glen Canyon Dam is made, a revised PRS will be prepared, and a 
new rate will be proposed, if needed.
4. O&M-Related Issues
    a. Western O&M: CREDA signed an agreement with Western and 
Reclamation dated September 24, 1992, which states:
    Western shall utilize the Work Program Information made available 
to its Customers by Western and Reclamation (including adjustments 
thereof which may result from reviews, from internal corrections or the 
dispute resolution process provided for in these Joint Procedures but 
excluding the costs of future transmission system additions in a 
Planning Year or Out Year which are conceptual in nature), to prepare 
the power repayment studies upon which it relies to promulgate any 
interim or final rates proposed or adopted for SLCAIP firm power or 
transmission services.
    Several customers and their member organizations are concerned 
about the implementation of the 1992 Agreement.
    (1) Comment: (One commentor) continues to be concerned with 
Western's inconsistent use of budgeted information in the preparation 
of the PRS . . . (the commentor) has been some-what frustrated in its 
attempts in this rate adjustment process to reconcile certain 
information used in the 1994 Rate Brochure PRS with the information 
previously provided in the Work Program review process.
    Response: The FY 1995 Work Program is merely a copy of the proposed 
FY 1994 Congressional Budget Submission. It was used as the starting 
point in planning expenditures for the FY 1995 congressional budget.
    CREDA's September 1992 agreement with Western and Reclamation 
allows power customers to have meaningful input to the new 
congressional budget. However, this work program document is prepared 
too early in the planning process for either customers or Western to 
say that no further changes will be made. Western feels that the timing 
and use of documents stated in the agreement should be revisited. 
Western is willing to continue to work with the customers in improving 
the budget and work plan review process in the future.
    To illustrate the process, the transformation of the FY 1995 Work 
Program into the final FY 1995 Budget is outlined below:
    (a) (The commentor) reviewed the FY 1995 Work Program and had 
opportunity to make suggested changes.
    (b) The revised FY 1995 Work Program became the FY 1995 Internal 
Review Budget. At this point, more changes were made. Those changes 
then were reviewed by Western. Further changes, usually a lowering of 
spending projections, are common in this stage of budget preparation.
    (c) The FY 1995 Internal Review Budget was then sent to Washington 
to be approved by DOE. There are usually reductions in spending 
estimates at this stage, as well, dictated by DOE's spending 
priorities. The DOE-approved budget was called the FY 1995 OMB Budget 
Request and was sent to that agency for review and approval. Any 
changes were then incorporated into a document called the FY 1995 
Congressional Budget Submission.
    (d) Finally, the FY 1995 Congressional Budget Submission went 
before Congress, where any final changes desired by the legislative 
branch of Government were made. Only after it was approved by Congress 
after public debate was the final FY 1995 Budget determined.
    The FY 1994 Congressional Budget Submission was officially sent to 
Congress in January 1993. When the April 1994 rate brochure PRSs were 
being prepared, the data in the FY 1994 Congressional Budget 
Submission/1995 Work Program was already more than 2 years old (having 
begun as the FY 1994 Work Program in early 1992). Because of this 
timing, most of the information was outdated.
    Western had completed turning the FY 1995 Work Program into the FY 
1995 Congressional Budget Submission by that time. As is usually the 
case, some of the planned expenditures had been deleted in the process. 
Further, because of extra impetus to keep costs down, a Western-wide 
decision was made in which O&M costs would be allowed to rise only 2-
percent per year between FYs 1994 and 1996.
    In keeping with Western's policy to set rates at the lowest 
possible level consistent with sound business principles, Western used 
data from the lower-cost (and more current) FY 1995 Congressional 
Budget Submission rather than that in the customer-reviewed FY 1995 
Work Program in the Rate Brochure PRS.
    When Reclamation, Western, and CREDA entered into the September 
1992 agreement, the parties did not anticipate that expenditure plans 
would change significantly between the Work Program review and the 
congressional budget submission. Events have proved otherwise.

         Comparison of FY 1995 Work Plan With FY 1995 Congressional Budget Submission O&M Expenses $000         
----------------------------------------------------------------------------------------------------------------
                                                 FY 1994    FY 1995    FY 1996    FY 1997    FY 1998    Totals  
----------------------------------------------------------------------------------------------------------------
1995 Work Plan:                                                                                                 
  Reclamation.................................    $17,898    $18,408    $17,403    $17,884    $16,739    $88,332
  Western.....................................     30,894     30,379     30,743     31,481     33,905   157,402 
                                               -----------------------------------------------------------------
  Total.......................................     48,792     48,787     48,146     49,365     50,644    245,734
1995 Budget:                                                                                                    
  Reclamation.................................    $15,856    $15,925    $16,041    $16,262    $16,631    $80,715
  Western.....................................     29,307     27,635     27,971     28,724     28,984   142,621 
                                               -----------------------------------------------------------------
    Total.....................................     45,163     43,560     44,012     44,986     45,615   223,336 
                                               -----------------------------------------------------------------
      Decreased Cost to Customers.............     -3,629     -5,227     -4,134     -4,379     -5,029   -22,398 
----------------------------------------------------------------------------------------------------------------

    (2) Comment: Two comments expressed concern that: Western's 
projected O&M expenses for 1994 are more than 25-percent higher than 
actual O&M expenses in 1993 and more than 20-percent higher than the 
1994 O&M expenses included in the 1995 Work Program documents.
    Response: Western has been unable to duplicate the analysis in this 
comment. Some of the figures in the commentor's table are incorrect. 
This gives the impression of a problem where Western believes none 
exists. Most significantly, Western's actual FY 1993 CRSP O&M expense 
of $17.964 million shown in the commentor's tables is incorrect. The 
proper amount, from the Results of Operations (financial statements) as 
shown below, is $21.418 million. This should be the basis for the 
commentor's percentage calculations.
    Below is a table comparing the table submitted by the commentors, 
the FY 1995 Work Program, and the amounts used in the PRS. 

                                           Western's CRSP O&M ($000)                                            
----------------------------------------------------------------------------------------------------------------
                                                             1993     1994     1995     1996     1997      1998 
----------------------------------------------------------------------------------------------------------------
Commentor's Table \1\.....................................   17,964   18,628   20,888   21,070   21,437   21,923
Annual Change (%).........................................        0        4       12        1        2        2
FY 1995 Work Program\2\...................................   26,449   24,555   23,898   24,202   24,882   27,245
Annual Change (%).........................................        0       -7       -3        1        3       10
Rate Brochure PRS \3\.....................................   21,418   22,530   20,888   21,070   21,437   21,993
Annual Change (%).........................................        0        5       -7        1        2       3 
----------------------------------------------------------------------------------------------------------------
\1\ From comment letter dated July 27, 1994; source of data identified as FY 1995 Work Program.                 
\2\ From FY 1995 Work Program (i.e., FY Congressional Budget submission), according to CRSP records.            
\3\ Using the FY 1995 Congressional Budget submission.                                                          

    The average annual growth rate in the rate brochure PRS from 1993 
through 1996 is a negative 0.33 percent. This is considerably below the 
2-percent maximum annual growth rate which is Western's goal.
5. Reclamation O&M
    a. Comment: Reclamation explained the increase in Regional Office 
expense in 1995 O&M expenses over the level shown in the 1995 Work 
Program (which was $564,000) as the inclusion of the Dolores Project 
O&M expense. The O&M expenses for the Dolores Project are shown in the 
1995 Work Program as $301,000 for 1995, leaving $263,000 of the 
increase in this account category unexplained.
    Response: The statement that the Regional Office expense in 1995 
included the Dolores Project is incorrect. The Regional Office expense 
category applies only to the initial CRSP units (i.e., Aspinall, 
Flaming Gorge, Glen Canyon, and Navajo), and not to the Dolores 
Project. Dolores Project costs are shown in their own, separate PF-3 
budget document.
    Regional Office expenses shown in the initial units (CRSP) work 
plan differ from those included in the PRS because Western 
inadvertently used an unofficial version of Reclamation's PF-3. This 
document did not differ from the official budget in total costs for the 
CRSP initial units. An adjustment within the program was made, which 
increased the Regional Office expense by $564,000. This was made to 
balance to the FY 1995 Budget Submission funding amount.
    b. Comment. The O&M figures (for the Rio Grande Project) in the PRS 
appear to double count capitalized moveable equipment (CME) expenses 
for the years 1995, 1997, and 1998 . . . .
    Response: Western agrees with the comment and has rerun the RGP 
study to eliminate this error.
    c. Comment: For 1994, the difference in expenses between the Work 
Program and the PRS appears to be comprised of the $35,000 for CME less 
a $20,500 expense reduction, which is unex- plained.
    Response: Western's numbers were correct and have been used in the 
PRS. The commentor's table shows a difference of $28,885. There are 
four reasons for the difference: (1) O&M expenditures planned for FY 
1993 on the Elephant Butte Dam of $67,548 (portion assigned to power = 
$67,548 X 20.8% = $14,050) were not spent in FY 1993, but were 
obligated and actually spent in 1994; (2) expenditures planned on the 
Elephant Butte Powerplant ($30,854, of which 100-percent is repayable 
by power revenues) were not spent in FY 1993, but were obligated and 
actually spent in FY 1994; (3) the $35,000 referred to as CME for FY 
1994 is not CME, but miscellaneous tools which is charged off to O&M 
and is properly includable in the total O&M for the year; and (4) item 
number (2) was further complicated by the fact that both the Work 
Program and the FY 1995 Budget Congressional Submission are based on an 
incorrect version of the summarized report. A line item (which should 
be included in the Other Expense line) which appears on the detailed 
report was coded incorrectly so that it does not appear on the 
summarized reports, but is included in the totals of both reports. 
Thus, the totals are $40,000 higher in the Work Program than the total 
of the numbers shown and $23,921 higher than the total of the numbers 
shown in the FY 1995 Congressional Budget Submission. The $40,000 
budgeted Other Expense item was later reduced to $23,921, which matches 
the $1,141,775 figure shown in the FY 1995 Congressional Budget 
Submission. Following is a table which recaps the above information 
starting with the figures shown in the commentor's table:

                        Elephant Butte Powerplant                       
------------------------------------------------------------------------
                                                                1995    
                                               1995 Work   congressional
                                                Program        budget   
                                                            submission  
------------------------------------------------------------------------
Salaries....................................     $532,000      $532,000 
Office General Expense......................      262,000       262,000 
CPA.........................................      173,000      173,000  
                                             ---------------------------
Other Expense\1\............................      120,000    150,854\2\ 
    Subtotal\3\.............................    1,087,000     1,117,854 
Missing Line Item\4\ (other expenses).......       40,000       23,921  
                                             --------------             
    Total\5\................................    1,127,000    1,141,775  
------------------------------------------------------------------------
\1\Other expenses should have been higher by $40,000 in both the FY 1995
  Work Program and the FY 1995 Congressional Budget Submission.         
\2\When summed, includes $30,850 carryover from FY 1993.                
\3\Actual summation of figure shown.                                    
\4\This amount should have been included in the ``other expense'' line  
  of both the FY 1995 work program and the FY 1995 Budget               
  Justifications.                                                       
\5\As displayed in the FY 1995 Work Program and the FY 1995             
  Congressional Budget Submission.                                      


Subtotal--Elephant Butte Powerplant O&M....................   $1,141,775
Less amount shown on commentor's table.....................   1,127,000 
                                                            ------------
    Subtotal...............................................       14,775
Add allocated carry-over amount from item (1) above........      14,050 
                                                            ------------
    Total difference shown on commentor's table............      28,825 
                                                            ------------
The average annual increase in projected O&M expenses which             
 results in a $8.2 million annual revenue requirement is                
 troublesome. How this figure was obtained in the modeling              
 effort undertaken at Western is not explained in detail in             
 the brochure. If the projected figure is based upon an                 
 extrapolation of historical data adjusted for inflation,               
 the cost figure may not reflect all of the possible areas              
 of cost reduction available to both Western and the Bureau             
 of Reclamation.                                                        
Response. Only two projections used in the Integrated                   
 Projects and/or CRSP PRS are based on computer modeling:               
 the water available for power production and the ultimate              
 power-related revenue requirements for the participating               
 projects. Estimates for future O&M expenses are taken                  
 directly from official budgets; the budgets include modest             
 approximations of labor cost increases. All equipment                  
 spending in the 5-year budget window is made up of actual              
 projections received from workers in the field, reporting              
 which equipment is likely to need replacement and when.                
 Miscellaneous revenue and expense projections are based on             
 historical averages and known future commitments.                      
b. Comment. A customer organization said:                               
The Energy Policy Act of 1992 (EPACT) has served as the                 
 catalyst for increasing competition in wholesale                       
 generation. They would anticipate that Western begin to                
 streamline its operations in order that it position itself             
 competitively in the new electricity market.                           
Response. Western's management is presently looking for                 
 ways to improve customer service while cutting costs                   
 through Western's Strategic Planning initiative. Some of               
 the decisions made to date include:                                    
(1) Delayering. This is a reduction in the number of                    
 supervisory employees, to reduce red tape and inertia                  
 while increasing customer service. The emphasis will be on             
 empowering the employees. The initiative is already under              
 way.4703                                                               
(2) Western will limit increases in annual operating                    
 expenses to less than 2-percent per project per year                   
 through FY 1996. Thereafter, increases in annual operating             
 expenses will not exceed the annual rate of inflation.                 
(3) As the marketing agent for Federal power, Western will              
 participate in the decision making process with other                  
 resource agencies whose operating decisions significantly              
 affect Federal power rate and repayment obligations                    
 whenever possible.                                                     
(4) Proposals for construction of new facilities will be                
 assessed using integrated resource planning principles and             
 must meet at least one of three criteria before                        
 construction may begin:                                                
(a) Increased revenues from new facilities must exceed                  
 their annual cost over the cost-evaluation period.                     
(b) Customers must benefit sufficiently to support new                  
 facilities in spite of a possible rate increase.                       
(c) The new facilities will be funded by non-Western                    
 sources.                                                               
A customer organization has a series of questions about                 
 construction-related cost projections.                                 
a. Comment: Some of the commentators said: ... they have                
 been unable to find support in the 1995 Work Program for a             
 majority of the significant (>$100,000) additions and                  
 replacements included in the 1994 rate brochure and rate               
 brochure PRS....                                                       
Response: For a detailed outline of the budget process,                 
 Western refers the reader to earlier replies to questions              
 about O&M. To reiterate, the FY 1995 Work Program had, in              
 many instances, higher cost projections than the FY 1995               
 Congressional Budget Submission. Western has used the                  
 lower figures in the ratesetting PRS.                                  
In the case of CRSP construction, this change dramatically              
 reduced the cost projections. Table VI on pages 12 and 13              
 of the April 1994 Rate Brochure shows a $276 million                   
 decrease in budgeted power-related construction costs                  
 through FY 1998 between the FY 1995 Work Program (referred             
 to in the brochure as the FY 1994 Congressional Budget                 
 Submission) and the FY 1995 Congressional Budget                       
 Submission. Western has used the lower figure where it is              
 considered reliable.                                                   
b. Comment: (The commentor) has been unable to find support             
 for the investments included in the Collbran/Rate Brochure             
 PRS.                                                                   
Response: It is not possible to find the correlation                    
 between the investments in a budget document or work                   
 program and those in a PRS without some intermediate                   
 steps.                                                                 
The annual figures in the 1995 Work Program are only                    
 planned cash expenditures. Investments are large items,                
 often taking more than 1 year to complete. The total spent             
 on any one investment, then, is the sum of the annual                  
 expenditures shown in the work programs, plus any                      
 applicable IDC.                                                        
Western is required to record an investment in a PRS in the             
 year that it becomes operational. This permits the                     
 establishment of the proper repayment period and begins                
 the annual payment of interest on investment (due until                
 the investment's cost is completely repaid). Future                    
 investments appear in a PRS in the year they are planned               
 to be in-service, if that is within the 5-year budget                  
 window. Future investments (excluding future replacements)             
 planned for completion at some time after the 5-year                   
 window are normally excluded from a PRS, unless                        
 legislation directs otherwise (as is the case with the                 
 CRSP's participating projects). Annual cash outlays for an             
 investment that takes more than 1 year to complete have no             
 counterpart in a PRS. Indeed, there may be several years               
 of investment costs shown in work programs and budgets                 
 which do not appear in PRSs. However, the total sum, plus              
 IDC, will appear in the PRS in the year when the item is               
 anticipated to be operational.                                         
It is not unusual for the first future year in a budget                 
 document to show projections higher than those shown in                
 the previous budget document for that same year. It is                 
 common to have obligated amounts at the end of the year                
 just closed that do not get paid in that year. They are                
 then carried over and added to the next year. Also, CWIP               
 that has been completed, but that did not get moved to                 
 plant-in-service in the financial records, is carried over             
 to the next year (with the assumption that it will be                  
 moved to plant-in-service at that time). This also adds to             
 the total amount shown in the subsequent year.                         
c. Comment: (The commentor's) Table 7 below uses                        
 information provided in response to WAPA/CREDA-76 to                   
 illustrate the differences between the 1995 Work Program               
 and the PRS.4703                                                       
(The commentor) believes that some or all of the decrease               
 may result from elimination or reduction of dam repair                 
 work described in Reclamation's response to (the                       
 commentor's) comments on the 1995 Work Program review. The             
 increases (i.e., increases over and above the amounts                  
 shown in the 1995 Work Program) are unexplained, however,              
 by changes presented in the 1995 Work Program. Therefore,              
 (the commentor) recommends use of the investments shown in             
 line 31 of table 7 in the Collbran/Rate PRS.                           
Response: Table 7 in the commentor's July 27 comment letter             
 displays Collbran investment as shown in the FY 1995 Work              
 Program. Western agrees with the commentor's figures for               
 FY 1994 through FY 1998, except that carry-over from FY                
 1993 must also be added to FY 1994's total number.                     
 Western's brochure study also contained some figures from              
 the FY 1995 Congressional Budget Submission. There have                
 since been changes to that budget that have reduced some               
 of those costs by approximately $450,000. Western has                  
 rerun the Collbran ratesetting PRS using these changes.                
The following table illustrates how incremental investment              
 in budget figures is transformed into a PRS entry. Figures             
 from Reclamation's FY 1995 Work Program are used. The                  
 Collbran Project was used for this example because it                  
 contains no IDC or multipurpose investment, thereby                    
 simplifying the                                                        
 illustration.47038,L2,i1,s100,4,4,4,4,4,5,5                            
Per FY 1995 Work Plan:                                                  
  Big Meadows Dam..........................................          200
  Cottonwood Dam #2........................................           72
  Atkinson Dam.............................................  ...........
  Big Creek Dam............................................           69
  Lambert Dam..............................................  ...........
                                                            ------------
    Total..................................................          341
Per PRS/Financial Statement Entries                                     
  Big Meadows Dam..........................................  ...........
  Cottonwood Dam #2........................................  ...........
  Atkinson Dam.............................................  ...........
  Big Creek Dam............................................  ...........
  Lambert Dam..............................................  ...........
                                                            ------------
    Total..................................................            0
                                                                        

    d. Comment: All years in the (Rio Grande) PRS except 1994 match the 
values from the 1995 Work Program. In 1994, the difference is $619,806. 
(The values shown in line 14 of Table 9 should be used in the PRS.)
    Response:  The commentor is correct. An additional $619,806 has 
been added to the work program amount shown in FY 1994. Not all of the 
work in the Work Program for FY 1993 was completed or posted in that 
year. The amounts not completed, including those obligated but not 
spent in 1993, were carried over into FY 1994. This was the case with 
the $619,806 noted by the commentor. This is necessitated because of 
Western and Reclamation's accounting procedures (as explained in the 
previous section on the Collbran Project), which require the total 
investment (including IDC) to be moved to the plant-in-service account 
in the year it becomes operational, rather than recording incremental 
amounts of annual spending.
    Western has used the figures recommended by the commentor. The 
figures are the basis for the projected investment through the cost 
evaluation period (FY 1994-98). However, these amounts do not appear in 
the PRS in those years. As previously explained (see the example of the 
Collbran Project above), these amounts (plus IDC, where applicable) are 
shown in the PRS in the year the particular investment is scheduled to 
go into service.
    e. Comment: Commentor stated that:
    The intent of the work program review was to provide a less formal 
process through which customers could receive information and provide 
input regarding Western's and Reclamation's programs, allowing for this 
same information to then be used in determining the adequacy of rates. 
In departing in the rate process from data developed in the FY 1995 
Work Program, the principal benefit of the process is effectively 
undone. Moreover, the departures were not trivial. For Western's O&M 
expenses, the 1994 figure used in the Rate Brochure PRS exceeds that 
contained in the FY 1995 Work Program by almost $4 million, or 20 
percent.
    In new construction projects, the commentor identified over $45 
million in additional investment included in the PRS that was not 
identified or had been excluded in the work program review.
    Response: Western has given a detailed explanation of the changes 
in the 1994 O&M figures between the FY 1995 Work Program and the 1993 
ratesetting PRS earlier in this Rate Order. Construction cost 
modifications are also listed in detail.
    Western disagrees with the thrust of the commentor's statement. As 
Western follows its policy to develop the lowest rate to consumers 
consistent with sound business principles, all power customers, 
including the commentor's members benefit.
    For example, the FY 1995 Work Program includes over $527 million in 
construction costs for the SLCAO alone. Deducting what would normally 
be excluded from the PRS because it is not planned for completion by FY 
1998 leaves $284 million. This figure ($284 million) is still more than 
double what Western finally included in the Rate Brochure PRS as new 
investment $131 million. The difference between these two figures (the 
$284 million in the FY 1995 Work Program and the $131 million in the 
Rate Brochure PRS) equals approximately 0.75 mills/kWh in the composite 
rate. In other words, following the commentor's instructions would have 
resulted in a \3/4\ mills/kWh higher firm power rate than Western is 
proposing. Finally, Western will continue to work with its customers to 
identify and correct problems with the work program review process.
8. Environmentally Related Expenses
    a. Comment: The sum of environmental costs in the 1994 Rate 
Brochure is more than $0.5 million greater in 1993 and 1994 than 
contained in the FY 1995 Work Program. Western's response to CREDA's 
information request (WAPA/CREDA 67) indicated that the additional costs 
in 1994 were explained by about $6.0 million in ``unliquidated 
obligation'' in 1993. While actual costs were indeed lower than planned 
in 1993, the reduction does not explain the still greater increase 
indicated in the 1994 rate brochures. Environmental study costs should 
be limited to the amounts (with some allowance for carryover from prior 
years) developed in the work program process.
    Response: To compare environmental costs spent and budgeted for FYs 
1993 and 1994 in the 1995 budget and work plan, the unliquidated 
obligations must be taken into consideration, as shown below: 

                     Environmental Expenses ($000)                      
------------------------------------------------------------------------
                                                                   New  
                                  FY 1993   FY 1994    Total     Total  
------------------------------------------------------------------------
1994 Rate Brochure Appendix.....   $11,885   $20,935   $32,820   $32,820
Adjustment......................         0       490       490    33,310
FY 93 Unliquidated Obligations..    -2,391         0    -2,391    30,919
FY 94 Unliquidated Obligations..     6,005    -6,005         0    30,919
                                 ---------------------------------------
    Total Obligations...........    15,499    15,420    30,919    30,919
FY 1995 Work Program............    16,788    15,463    32,251    32,251
FY 93 Unliquidated Obligations..    -2,391         0    -2,391   29,860 
                                 ---------------------------------------
    Total Obligations...........    14,397    15,463    29,860   29,860 
                                 ---------------------------------------
      Difference................     1,102       -43     1,059    1,059 
------------------------------------------------------------------------

    b. Comment: A customer organization says:
    It is clear that environmental expenses associated with Glen Canyon 
Dam have gotten out of hand, are not under control, and are not being 
subjected to any sort of cost-control analysis or audit. They urge 
Western to do what it can to urge the Bureau of Reclamation to limit 
environmental study expenditures to those that are calculated to 
produce necessary, credible information.
    Response: As a part of Western's Strategic Planning initiative: 
Western will, as the marketing agent for Federal power, participate in 
the decision making process whenever possible with other resource 
agencies whose operating decisions significantly affect Federal power 
rate and repayment obligations. Western will do so to sustain the 
marketability of the Federal hydroelectric resource.
9. Miscellaneous Comments
    Long-term Capacity Sales:
    (1) Comment: (The commentor) notes that there is a discrepancy 
between the projection of capacity sales shown in Western's ``1993 
Power Projections'' and the values in the PRS. Upon inspection of the 
two set of values, it appears that the values used in the PRS may have 
been misentered 1 year below the proper year. This causes the amount of 
capacity sales to be slightly understated in several years.
    Response: Western agrees. Western has checked these data and has 
found a disconnect between the kW of capacity sales estimate found in 
the work papers and that in the PRS. It appears that the data from FYs 
1993 through 2003 in the work papers were put into the PRS in FYs 1994 
through 2004. The error has been corrected.
    (2) Comment: Western calculates the PRS for Integrated Projects 
such that replacements are repaid up to the rate-setting year. In part, 
this is due to the assignment of a lower repayment priority (to 
irrigation) in the PRS. Assigning the lower priority (to irrigation) 
causes a less than optimal rate calculation, since the rate could be 
lowered by allowing for some replacements to remain unpaid beginning 9-
10 years prior to the ratesetting year.
    Response: Western recognizes that some replacements have been paid 
earlier in the PRS than required. Western conducted a test to determine 
if forcing payments to irrigation obligations would postpone early 
payment of replacements, thus lowering the rate. Forcing payments 
reduces the composite rate 0.13 mills/kWh. This change has been made in 
the ratesetting PRS.
10. Untimely Responses to Data Requests
    a. Comment: Three commentors stated that their consultant did not 
receive all the information needed to reconcile certain key portions of 
the proposed rate and did not have adequate time to verify all the data 
underlying the rate adjustment.
    Response: The consultant submitted five official data requests. 
Responses were as follows: 

------------------------------------------------------------------------
                                      Items of                          
 Data request received by western's     data      Information mailed by 
               SLCAO                 requested       western's SLCAO    
------------------------------------------------------------------------
May 13, 1994.......................          18  May 20, 1994.          
June 3, 1994.......................           9  June 23, 1994.         
June 24, 1994......................           9  June 30, 1994.         
July 1, 1994.......................          38  July 19, 1994.         
July 8, 1994.......................           8  July 14, 1994.         
  Total............................         82                          
------------------------------------------------------------------------

    Customers originally had 97 days to submit comments and request 
information; 56 of those days were after the public information forum. 
The largest and most detailed request for data was received by Western 
on July 1, 1994, which was 19 days before the original close of the 
comment period. The final response to this request was faxed to the 
consulting firm, on July 19, 1994, 1 day before the original end of the 
comment period. Western then extended the date it would accept comments 
to July 27, 1994, to provide commentors extra time to prepare a reply. 
Western believes that ample time has been allowed for public comment 
and that information was furnished to requestors in a timely manner. 
However, Western also recognizes that there could be confusion and 
misunderstanding regarding the information needed by the commentators 
and that some of the information received may not be what was needed. 
Western will continue to work with customers and interested parties to 
find a more efficient and acceptable process to respond to data 
requests and meet the commentors' needs.
    b. Comment: A customer organization said:
    Given the backdrop of structural changes in the industry and 
increasing environmental concerns over hydro power generation, it would 
seem that Western should develop a pricing policy based upon a firm 
understanding of price sensitivity. The lack of any such analysis is a 
major omission.
    Response: One of Western's primary concerns is the impact the 
prices for its products have on possible sales. Based on knowledge of 
the electrical power market, Western's proposed combined rates for firm 
power are below other sources of firm electrical power available to 
Integrated Projects customers. For this reason, Western has not 
undertaken a specific study to analyze price effects on the electrical 
power purchased by Western's Integrated Projects customers.
    There may be reductions of Integrated Projects energy usage in the 
short-term by Western's customers as a result of the proposed increase 
in the energy rate. Some of Western's Integrated Projects customers 
with their own electrical power generating resources may be faced with 
variable costs that allow them to produce energy more cheaply than 
purchasing from Western at the proposed new rate. Information on the 
cost of generation is considered sensitive and is not available to 
Western. However, published sources of information which relate to coal 
prices and other components of the variable costs of power generation 
indicate that the proposed energy rate is less than Western's estimate 
of their cost of generating thermal energy. Western has received no 
comments to indicate otherwise.
    c. Comment: To help customers respond more completely to Western's 
proposals, a customer organization suggests that, in the future, when 
Western entertains the thought of extending the time for commenting as 
done here, tie the extension to a period of time following completion 
of responses to requests for information.
    Response: Western believes that the existing customer review 
process and the public rate process sufficiently provide for both 
flexibility for input and measurability of the progress toward the 
completion of a rate.
    d. Comment: Several customers concur with changing the expression 
of the firm power rate from a `combined rate' to a `composite rate'.
    Response: Western agrees with the customer comment and believes 
that the composite rate will make the price of Integrated Projects 
power more easily comparable with that from other sources.
    e. Issue: A customer states that they believe it is very unfair to 
continue to increase the burden on the ratepayers to fund 
(environmental) studies which will result in further increases in costs 
and/or reductions in the amount of power available.
    Response: As noted earlier, Western is working with Reclamation to 
more closely monitor these costs.
    11. Issue Papers Resolution: Several issues which Western believes 
would have caused considerable protracted comment were discussed in 
detail during the pre-rate-adjustment process of informal meetings 
between various stakeholders and the exchange of issue papers. The 
stakeholders liked the process. The issues which were resolved in this 
process are summarized below:
    a. Identifying historic expenses related to the CRSP's Glen Canyon 
Unit that became nonreimbursable with the passage of the Grand Canyon 
Protection Act of 1992 (GCPA).
    b. Agreement about which future Glen Canyon Dam environmental costs 
have the potential to become nonreimbursable.
    c. General understanding of the functioning of the budget 
neutrality stipulations in the GCPA, stating that environmentally 
related expenses will be nonreimbursable for FY 1993 through FY 1997 
only to the extent that offsetting revenues are received by the 
Treasury from other GCPA provisions.
    d. The timing of the reallocation of the construction costs of the 
Glen Canyon Unit.
    e. Identification of those costs of the Central Utah 
(participating) Project which are properly excluded from influencing 
the Integrated Projects firm power rate.
    f. Implementation of a procedure to assure that the Basin Fund has 
sufficient cash on hand to pay all operating costs for the CRSP.

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 OMB is required.

Availability of Information

    Information regarding this rate adjustment, including PRSs, 
comments, letters, memoranda, and other supporting material made or 
kept by Western for the purpose of developing the power rates, is 
available for public review in the following locations.

Salt Lake City Area Office, Western Area Power Administration, Office 
of the Assistant Area Manager for Power Marketing, 257 East 200 South, 
Suite 475, Salt Lake City, UT 84111
Western Area Power Administration, Division of Marketing and Rates, 
1627 Cole Boulevard, Golden, CO 80401
Western Area Power Administration, Office of the Assistant 
Administrator for Washington Liaison, Room 8G-027, Forrestal Building, 
1000 Independence Avenue SW., Washington, DC 20585

Submission to Federal Energy Regulatory Commission

    The rate herein confirmed, approved, and placed into effect on an 
interim basis, together with supporting documents, will be 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 December 1, 1994, Rate Schedule SLIP-F5. The rate 
schedule shall remain in effect on an interim basis, pending FERC 
confirmation and approval of it or a substitute rate on a final basis, 
through November 30, 1999.

    Issued in Washington, D.C., October 24, 1994.
William H. White,
Deputy Secretary.

Salt Lake City Area Integrated Projects; Arizona, Colorado, Nevada, New 
Mexico, Utah, Wyoming; Schedule of Rates for Firm Power Service

Effective

    Beginning December 1, 1994, through November 30, 1999, or until 
superseded by another rate schedule, whichever occurs earlier.

Available

    In the area served by the Salt Lake City Area Integrated Projects.

Applicable

    To the wholesale power customers for firm power service supplied 
through one meter at one point of delivery, or as otherwise established 
by contract.

Character

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

Monthly Rate

    Demand Charge: $3.83 per kilowatt of billing demand.
    Energy Charge: 8.90 mills per kilowatthour of use.

Billing Demand

    The billing demand will be the greater of:
    1. The highest 30-minute integrated demand measured during the 
month up to, but not more than, the delivery obligation under the power 
sales contract, or
    2. The contract rate of delivery.

Adjustment for Transformer Losses

    If delivery is made at transmission voltage but metered on the low-
voltage side of the substation, the meter readings will be increased to 
compensate for transformer losses as provided for in the contract.

Adjustment for Power Factor

    The customer will be required to maintain a power factor at all 
points of measurement between 95-percent lagging and 95-percent 
leading.

Adjustment for Purchased Resources

Purpose of Adjustment
    To ensure that Western Area Power Administration (Western) has 
sufficient revenues to support resource purchases made necessary 
because of restricted generation from Glen Canyon Dam as the result of 
restrictions on water releases from the dam.
Applicability
    To those contractors who are not receiving service under an Interim 
Purchase Amendment to the firm power sales contract.
Adjustment
    If Western finds it necessary to purchase resources to replace 
generation lost at Glen Canyon Dam because of the above-listed 
restrictions, Western will, beginning on the first month that such 
purchases are made, include in the contractor's monthly power bill an 
estimate of that contractor's proportionate share of net capacity 
purchase costs. The cost of purchasing these resources will be offset 
by the revenue that Western receives for the sale of energy, if any, 
associated with the purchased resources.
    In its October bill each year, Western will reconcile the previous 
fiscal year's actual purchased power expenses and the monthly estimated 
costs paid by the contractor. If the contractor has paid more than its 
proportionate share of actual purchased power expenses, the excess 
amount will be shown as a credit to the contractor's October power 
bill. If the contractor has paid less than its proportionate share of 
actual power purchase expenses, Western will add such amount to the 
contractor's October power bill.

Notification
    If Western finds it necessary to implement this adjustment, it will 
give a one-time notification to the contractor and the Federal Energy 
Regulatory Commission at least 10 days before initially adding 
purchased power cost to the contractor's monthly bill.

[FR Doc. 94-27306 Filed 11-2-94; 8:45 am]
BILLING CODE 6450-01-P