Loveland Area ProjectsNotice of Rate Order No. WAPA-61

DEPARTMENT OF ENERGY

Western Area Power Administration

Loveland Area Projects--Notice of Rate Order No. WAPA-61

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of Rate Order No. WAPA-61 Loveland Area Projects Firm

Electric Service and Transmission Rate Adjustments.

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

SUMMARY: Notice is given of the confirmation and approval by the Deputy

Secretary of the Department of Energy (DOE) of Rate Order No. WAPA-61

and Rate Schedules L-F4, L-T3, and L-T4 placing increased firm power

rates for capacity and energy and increased firm and nonfirm

transmission rates from the Loveland Area Projects (LAP) into effect on

an interim basis. The interim rates, called the provisional rates, will

remain in effect on an interim basis until the Federal Energy

Regulatory Commission (FERC) confirms, approves, and places them into

effect on a final basis or until they are replaced by other rates.

The Post-1989 General Power Marketing and Allocation Criteria;

Pick-Sloan Missouri Basin Program-Western Division (Criteria) were

published in the Federal Register on January 31, 1986, (51 FR 4012).

The Criteria contractually integrated the resources of the P-SMBP-WD

and the Fryingpan-Arkansas Project (Fry-Ark), both commonly referred to

as the LAP, and called for the establishment of an initial rate for LAP

power.

The combined results of the fiscal year (FY) 1992 power repayment

study (PRS) for the Pick-Sloan Missouri Basin Program (P-SMBP) and the

FY 1992 PRS for Fry-Ark indicate that the existing rates do not yield

sufficient revenue to satisfy the cost-recovery criteria through the

study periods. The proposed P-SMBP-Eastern Division rate schedules in

Rate Order No. WAPA-60 along with the Pick-Sloan Missouri Basin

Program-Western Division (P-SMBP-WD) revenue requirement, will yield

adequate revenue to satisfy the cost-recovery criteria for the P-SMBP.

Rate Order No. WAPA-61 includes the revenue requirement for the P-SMBP-

WD that was discussed in Rate Order No. WAPA-60, and will also satisfy

the cost-recovery criteria for Fry-Ark. The LAP firm power rate was

developed by combining the revenue requirements from the FY 1992 PRSs

for both the P-SMBP-WD and Fry-Ark.

A comparison of existing and provisional rates follows:

Lap Provisional Rate Changes

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

Provisional rates, February 1, 1994, Provisional rates, October 1, 1994,

Existing rate (FY-1993) and percent change and percent change

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

Rate Schedule........................... L-F3.......................... L-F4.................................. L-F4.

Composite Rate.......................... 20.06 (mills/kWh)............. 20.67 (mills/kWh) 3.0%................ 21.70 (mills/kWh) 5.0%

Firm Energy............................. 10.03 (mills/kWh)............. 10.33 (mills/kWh) 3.0%................ 10.85 (mills/kWh) 5.0%

Firm Capacity........................... $2.58 ($/kW-month)............ $2.65 ($/kW-month) 2.7%............... $2.85 ($/kW-month) 7.5%

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

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Percent of

Class of service Existing rate (FY 1993) Provisional rate, February 1, 1994 change

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

Firm Transmission........ $1.52 ($/kW-month)................. $1.88 ($/kW-month)................. 23.7

Nonfirm Transmission..... 2.1 (mills/kWh).................... 2.6 (mills/kWh).................... 23.8

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

DATES: Rate Schedules L-F4, L-T3, and L-T4 will be placed into effect

on an interim basis on the first day of the first full billing period

beginning on or after February 1, 1994, and will be in effect until

FERC confirms, approves, and places the rate schedules into effect on a

final basis for a 5-year period, or until the rate schedules are

superseded.

FOR FURTHER INFORMATION CONTACT:

Mr. Stephen A. Fausett, Loveland Area Office, Western Area Power

Administration, P.O. Box 3700, Loveland, CO 80539-3003, (303) 490-

7201

Ms. Deborah Linke, Director, Division of Marketing and Rates,

Western Area Power Administration, P.O. Box 3402, Golden, CO 80401-

3398, (303) 231-1545

Mr. Joel Bladow, Assistant Administrator for Washington Liaison,

Western Area Power Administration, Room 8G-061, Forrestal Building,

1000 Independence Avenue SW., Washington, DC 20585-0001, (202) 586-

5581

SUPPLEMENTARY INFORMATION: By Amendment No. 3 to Delegation Order No.

0204-108, published November 10, 1993 (58 FR 59716), the Secretary of

Energy delegated (1) the authority to develop long-term power and

transmission rates on a nonexclusive basis to the Administrator of

Western Area Power Administration (Western); (2) the authority to

confirm, approve, and place such rates into effect on an interim basis

to the Deputy Secretary; and (3) the authority to confirm, approve, and

place into effect on a final basis, to remand, or to disapprove such

rates to FERC. Existing DOE procedures for public participation in

power rate adjustments (10 CFR part 903) became effective on September

18, 1985 (50 FR 37835). These power rates are established pursuant to

section 302(a) of the DOE Organization Act, 42 U.S.C. 7152(a), through

which the power marketing functions of the Secretary of the Interior

and the Bureau of Reclamation (Reclamation) under the Reclamation Act

of 1902, 43 U.S.C. 371 et seq., as amended and supplemented by

subsequent enactments, particularly section 9(c) of the Reclamation

Project Act of 1939, 43 U.S.C. 485h(c), and other acts specifically

applicable to the project system involved, were transferred to and

vested in the Secretary of Energy (Secretary).

The March 1993 customer brochure explaining the background for the

proposed LAP firm power and transmission rates adjustment was

distributed to all LAP customers and interested parties. In accordance

with procedures for public participation in general rate adjustments

(10 CFR part 903), the comment and consultation period was initiated on

July 8, 1993, with the publication of a Federal Register notice

announcing the proposed rate and procedures for public participation

(58 FR 36682). A public information forum was held on July 20, 1993, in

Northglenn, Colorado. The public comment forum was held on August 30,

1993, in Northglenn, Colorado. The consultation and comment period

ended on October 6, 1993. During this period, interested parties made

comments to Western concerning the proposed rates. Two comment letters

were received, and three people commented orally. All comments were

considered in the preparation of the rate order. Western has concluded

that the LAP rate adjustments are necessary to meet cost recovery

criteria.

In Rate Order No. WAPA-61, results of the Fry-Ark ratesetting PRS

are being compared to the FY 1990 PRS, which is the basis for the

existing rates.

This Rate Order also reflects the revenue requirements for the P-

SMBP-WD. The comparison shows the following differences:

1. The projected operations and maintenance (O&M) expenses

increased for both projects. The P-SMBP-WD O&M expenses for the 100-

year study period have increased by a total of $10.2 million per year,

and Fry-Ark O&M expenses for the 50-year study period have increased by

$0.6 million per year.

2. The purchased power costs projected over the future 6-year

period for P-SMBP-WD are $113 million. These costs are partially

attributable to the extended drought which necessitated Reclamation and

the Corp of Engineers to draw down the reservoirs to an extremely low

level. This has caused Western to project future purchased power

expenses for the next few years until the reservoirs are full again.

Although FY 1993 was an above-average water year, purchased power

expenses are continuing to be projected because the flooding in the

Mid-west severely restricted water releases and therefore severely

curtailed power generation.

3. The revised Fry-Ark cost allocations reduced the overall project

investment costs by over $38.5 million.

Of the above factors, the one item with the greatest rate impact is

the drought, which is reflected in the purchased power expenses and

capitalized unpaid annual expenses. The second greatest impact comes

from O&M expenses which are increasing due to inflation as well as

responding to programmatic and administrative requirements, such as

safety programs and environmental compliance.

Rate Order No. WAPA-61, confirming, approving, and placing the

proposed LAP rate adjustments into effect on an interim basis is

issued, and the new Rate Schedules L-F4, L-T3, and L-T4 will be

submitted promptly to FERC for confirmation and approval on a final

basis.

Issued in Washington, D.C., January 6, 1994.

Bill White,

Deputy Secretary.

Order Confirming, Approving, and Placing the Loveland Area Projects

Firm Power and Transmission Service Rates Into Effect on an Interim

Basis

January 6 , 1994.

In the matter of: Western Area Power Administration Rate

Adjustments for Loveland Area Projects; Rate Order No. WAPA-61.

These power rates are established pursuant to section 302(a) of the

Department of Energy (DOE) Organization Act, 42 U.S.C. 7152(a), through

which the power marketing functions of the Secretary of the Interior

and the Bureau of Reclamation (Reclamation) under the Reclamation Act

of 1902, 43 U.S.C. 371 et seq., as amended and supplemented by

subsequent enactments, particularly section 9(c) of the Reclamation

Project Act of 1939, 43 U.S.C. 485h(c), and other acts specifically

applicable to the Pick-Sloan Missouri Basin Program and the Fryingpan-

Arkansas Project, were transferred to and vested in the Secretary of

Energy.

By Amendment No. 3 to Delegation Order No. 0204-108, published

November 10, 1993 (58 FR 59716), the Secretary of Energy delegated (1)

the authority to develop long-term power and transmission rates on a

nonexclusive basis to the Administrator of the Western Area Power

Administration (Western); (2) the authority to confirm, approve, and

place such rates into effect on an interim basis to the Deputy

Secretary; and (3) the authority to confirm, approve, and place into

effect on a final basis, to remand, or to disapprove such rates to the

Federal Energy Regulatory Commission (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:

$/kW-month: Monthly charge for capacity (usage--$per kilowatt-

month).

$/kW-year: The annual transmission revenue requirement divided by

the reserved annual transmission capacity.

AC: Alternating current.

BAO: Billings Area Office.

Criteria: Post-1989 General Power Marketing and Allocation Criteria;

Pick-Sloan Missouri Basin Program-Western Division, 51 FR 4012

(January 31, 1986).

CROD: Contract rate of delivery.

Customer Brochure: A document prepared for public distribution

explaining the background of the rate proposals contained in this

rate order.

DC: Direct current.

DOE: Department of Energy.

DOE Order RA 6120.2: An order dealing with power marketing

administration financial reporting.

FERC: Federal Energy Regulatory Commission.

Fry-Ark: Fryingpan-Arkansas Project.

FY: Fiscal year.

GWh: Gigawatthour.

kW: Kilowatt.

kW-month: The greater of (1) the highest 30-minute demand measured

during the month, not to exceed the contract obligation, or (2) the

contract rate of delivery.

kWh: Kilowatthour.

L-F3: Loveland Area Projects existing firm power rate. (Effective

permanently January 28, 1992.)

L-F4: Loveland Area Projects provisional firm power rate. (Effective

February 1, 1994.)

L-T1: Loveland Area Projects existing firm transmission service

rate. (Effective permanently April 29, 1991.)

L-T2: Loveland Area Projects existing nonfirm transmission service

rate. (Effective permanently April 29, 1991.)

L-T3: Loveland Area Projects provisional firm transmission service

rate. (Effective February 1, 1994.)

L-T4: Loveland Area Projects provisional nonfirm transmission

service rate. (Effective February 1, 1994.)

LAO: Loveland Area Office.

LAP: Loveland Area Projects.

MAPP: Mid-Continent Area Power Pool.

MBSG: Missouri Basin Systems Group.

mills/kWh: Mills per kilowatthour.

MW: Megawatt.

NEPA: National Environmental Policy Act of 1969.

O&M: Operation and maintenance.

PMA: Power marketing administration.

PRS: Power repayment study.

P-SMBP: Pick-Sloan Missouri Basin Program.

P-SMBP-ED: Pick-Sloan Missouri Basin Program-Eastern Division.

P-SMBP-WD: Pick-Sloan Missouri Basin Program-Western Division.

Reclamation: Bureau of Reclamation, U.S. Department of the Interior.

Treasury: Secretary of the U.S. Department of Treasury.

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

February 1, 1994, and will be in effect pending FERC's approval of

them, or substitute rates, on a final basis for a 5-year period, or

until superseded.

Public Notice and Comment

The procedures for public participation in power and transmission

rate adjustments and extensions, 10 CFR part 903, have been followed by

Western in the development of these firm power and transmission rates.

The provisional firm power rates represent an increase of more than 1

percent in total LAP revenues; therefore, it is a major rate adjustment

as defined at 10 CFR 903.2(e) and 903.2(f)(1). The distinction between

a minor and a major rate adjustment is used only to determine the

public procedures for the rate adjustment.

The following summarizes the steps Western took to ensure

involvement of interested parties in the rate process:

1. Discussion of the proposed rate adjustments was initiated on

January 29, 1993, when a letter announcing an informal customer meeting

was mailed to all firm power customers and other interested parties.

The meeting was held on February 9, 1993, in Denver, Colorado. At this

informal meeting, Western representatives explained the need for the

rate increases and answered questions from those attending.

2. On March 12, 1993, a customer brochure was mailed to all

customers and other interested parties, advising them of the delay in

publishing the Federal Register notice. The public information and

public comment forums were also delayed.

3. A Federal Register notice was published on July 8, 1993 (58 FR

36682), officially announcing the proposed firm power and transmission

rate adjustments, initiating the public consultation and comment

period, announcing the public information and public comment forums,

and presenting procedures for public participation.

4. On July 9, 1993, letters were mailed to all LAP firm power and

transmission customers and other interested parties announcing the

publication of the Federal Register notice of July 8, 1993, and the

public information and public comment forums.

5. At the formal public information forum held on July 20, 1993,

Western explained the need for the rate increases in greater detail and

answered questions.

6. At the formal public comment forum on August 30, 1993, three

persons representing customers and customer groups made oral comments.

7. Western received an extensive request for information from one

customer group. We responded by providing data and background

information for the ratesetting PRS.

8. On September 17, 1993, Western sent a letter to all customers

and interested parties answering questions from the July 20, 1993,

public information meeting that were not resolved at that meeting.

9. Three comment letters were received during the 91-day

consultation and comment period. The consultation and comment period

ended October 6, 1993. All formally submitted comments have been

considered in the preparation of this rate order.

Project History

Pick-Sloan Missouri River Basin Program

The initial stages of the Missouri River Basin Project were

authorized by section 9 of the Flood Control Act of 1944 (Pub. L. 534,

58 Stat. 877, 891). The Missouri River Basin Project, later renamed the

P-SMBP to honor its two principal authors, has been under construction

since 1944. The P-SMBP encompasses a comprehensive program of flood

control, navigation improvement, irrigation, municipal and industrial

(M&I) water development, and hydroelectric production for the entire

Missouri River Basin. Multipurpose projects have been developed on the

Missouri River and its tributaries in Colorado, Montana, Nebraska,

North Dakota, South Dakota, and Wyoming.

Fryingpan-Arkansas Project

The Fry-Ark is a transmountain diversion development in

southeastern Colorado authorized by the Act of Congress on August 16,

1962 (Pub. L. 87-590, 76 Stat. 389, as amended by Title XI, Pub. L. 93-

493, 88 Stat. 1486, 1497 (1974)). The Fry-Ark diverts water from the

Fryingpan River and other tributaries of the Roaring Fork River in the

Colorado River Basin on the West Slope of the Rocky Mountains to the

Arkansas River on the East Slope of the Continental Divide. The water

diverted from the West Slope, together with regulated Arkansas River

water, provides supplemental irrigation, M&I water supplies, and

produces hydroelectric power. Flood control, fish and wildlife

enhancement, and recreation are other important purposes of Fry-Ark.

Loveland Area Projects

The Post-1989 General Power Marketing and Allocation Criteria: P-

SMBP-WD (Criteria), published in the Federal Register notice on January

31, 1986 (51 FR 4012), effectively integrated the resources of the P-

SMBP-WD and the Fry-Ark. This operational and contractual integration,

known as LAP, has allowed an increase in marketable resource,

simplification of contract administration, and establishment of a

blended rate of LAP power sales.

However, the P-SMBP and Fry-Ark retain separate financial status.

For this reason, separate PRSs are prepared for each project on an

annual basis. These PRSs are used to determine the ability of the power

rate to generate sufficient revenue for repayment of project investment

and cost during each project's prescribed repayment period. The revenue

requirement from the Fry-Ark PRS is combined with the P-SMBP-WD revenue

requirement derived from the P-SMBP PRS, to develop one rate for LAP

firm power sales.

A complete discussion of the project histories is found in the

March 1993 customer brochure, which is included in the supporting

documentation.

Power Repayment Studies

PRSs are prepared each FY to determine if power revenues will be

sufficient to pay, within the prescribed time periods, all costs

assigned to the power function. Repayment criteria are based on law,

policies, and authorizing legislation. DOE Order RA 6120.2, section

12b, requires that:

In addition to the recovery of the above costs (operation and

maintenance and interest expenses) on a year-by-year basis, the

expected revenues are at least sufficient to recover (1) each dollar

of power investment at Federal hydroelectric generating plants

within 50 years after they become revenue producing, except as

otherwise provided by law; plus, (2) each annual increment of

Federal transmission investment within the average service life of

such transmission facilities or within a maximum of 50 years,

whichever is less; plus, (3) the cost of each replacement of a unit

of property of a Federal power system within its expected service

life up to a maximum of 50 years; plus, (4) each dollar of assisted

irrigation investment within the period established for the

irrigation water users to repay their share of construction costs;

plus, (5) other costs such as payments to basin funds, participating

projects, or States.

Existing and Provisional Rates

Power Rates

The existing firm power rates and the provisional firm power rates

necessary to meet the revenue requirements for the LAP are listed

below. The provisional rates will be implemented in two steps. Step 1

rates are to become effective on an interim basis on the first day of

the first full billing period beginning on or after February 1, 1994.

Step 2 rates are to become effective on the first day of the first full

billing period beginning on or after October 1, 1994.

A comparison of existing and provisional rates follows:

LAP Provisional Power Rate Changes

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

Provisional rates February Provisional rates October

Existing rates 1, 1994, and percent 1, 1994, and percent

(FY 1993) change change

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Rate schedule.......................... L-F3 L-F4 L-F4

Composite rate (mills/kWh)............. 20.06 20.67--3.0% 21.70--5.0%

Firm energy (mills/kWh)................ 10.03 10.33--3.0% 10.85--5.0%

Firm capacity ($/kW-month)............. $2.58 $2.65--2.7% $2.85--7.5%

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

Transmission Rates

The existing transmission rates and provisional transmission rates

necessary to meet the revenue requirements for the LAP are listed

below. The rates are to become effective on an interim basis the first

day of the first full billing period beginning on or after February 1,

1994.

LAP Provisional Transmission Rate Changes

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Percent

Class of service Existing rates (FY 1993) Provisional rates February 1, of change

1994

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Firm Transmission.............. $1.52 ($/kW-month)............... $1.88 ($/kW-month)............... 23.7

Nonfirm Transmission........... 2.1 (mills/kWh).................. 2.6 (mills/kWh).................. 23.8

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

Certification of Rate

Western's Administrator has certified that the LAP firm power and

transmission rates placed into effect on an interim basis herein are

the lowest possible consistent with sound business principles. The

rates have been developed in accordance with administrative policies

and applicable laws.

Discussion

Firm Power

The Criteria were published in the Federal Register notice on

January 31, 1986 (51 FR 4012). The Criteria operationally and

contractually integrated the resources of the P-SMBP-WD and Fry-Ark.

The integrated resources are referred to as LAP. A blended rate was

established for the sale of LAP power.

The P-SMBP ratesetting PRS reflects the P-SMBP-WD revenue

requirement for the firm power sales as follows:

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

P-SMBP-WD

revenue

requirement

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

Proposed Increase (February 1994):

Present Revenue Requirement--13.73 mill/kWh x

2,036,000,000 kWh...................................... $27,954,280

Proposed First Step Increase 1.15 mills/kWh x

2,036,000,000 kWh...................................... 2,341,400

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

Total................................................. 30,295,680

=============

Proposed Increase (October 1994):

Revenue Requirement-First Increment--14.88 mills/kWh x

1,988,000,000 kWh\1\................................... 29,581,440

Proposed Second Step Increase--.92 mills/kWh x

1,988,000,000 kWh...................................... 1,828,960

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

Total................................................. 31,410,400

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

\1\Adjusted down from the previous year to reflect actual firm energy

under contract - 1,988,000,000 kWh x 14.88 mills, which is the FY 1993

Western Division composite rate of 13.73 mills plus the increase of

1.15 mills.

The Fry-Ark ratesetting PRS, adjusted to incorporate the savings of

the approved final cost allocation, indicates a decrease in the revenue

requirement from $13,933,200 to $12,855,560 per year. This decrease was

due primarily to an adjustment of approximately $39 million to project

investment as a result of Reclamation's approved final cost allocation

for Fry-Ark. The total Fry-Ark revenue requirement is as follows:

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

Fry-Ark

Revenue

requirement

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

Present Revenue Requirement............................... $13,933,200

Proposed Decrease......................................... -1,077,640

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

Total Proposed Fry-Ark Revenue Requirement.............. 12,855,560

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

The Fry-Ark revenue requirement contains two components. The

project has an average annual energy generation of 52,000,000 kWh from

flow-through water. This energy is assigned the current LAP energy

value; i.e., 10.03 mills/kWh. The remaining revenue requirement is

derived from the firm capacity component. This is a procedure used in

the study to account for the Fry-Ark portion of the energy marketed by

LAP.

A table comparing the LAP existing revenue requirement to the

proposed revenue requirement is shown below:

Summary of LAP Revenue Requirements

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

Proposed Proposed

Current February 1994 October 1994

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

P-SMBP-WD............ $27,954,280 $30,295,680 $31,410,400

Fry-Ark.............. 13,933,200 12,855,560 12,855,560

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

Total Lap........ 41,887,480 43,151,240 44,265,960

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

To establish the LAP rate. Western developed the revenue

requirements for LAP from the FY 1992 PRSs for both the P-SMBP and Fry-

Ark (Fry-Ark was subsequently adjusted to incorporate the approved

final cost allocation), as shown above. The revenue requirements from

both projects were combined to develop the LAP revenue requirement of

$43,151,240 for the first increment effective on the first day of the

first full billing period beginning on or after February 1, 1994, and

$44,265,960 for the second increment effective on the first day of the

first full billing period beginning on or after October 1, 1994. To

meet the LAP revenue requirements, the two-step rates for firm capacity

and energy were developed and proposed in the March 1993 Customer

Brochure for LAP. This brochure explains the background for the LAP and

how the rate design concept was developed. The brochure was distributed

to all LAP customers and other interested parties. The rate increase is

necessary to satisfy the cost-recovery criteria set forth in DOE Order

RA 6120.2.

Transmission Rate

Prior to August 1, 1982, a transmission rate of 1.0 mill/kWh was

included in transmission service contracts. The first firm transmission

service rate schedule was Schedule P-S WD-T1, which became effective on

August 1, 1982. This schedule was the first P-SMBP-WD transmission rate

that included a capacity charge. The rates under this schedule were 1.1

mills/kWh or $9.60/kW-year. Schedule P-S WD-T3 superseded Schedule P-S

WD-T1 on January 1, 1985, with a rate of 1.3 mills/kWh or $11.40/kW-

year. The present rate, Rate Schedule L-T1, superseded Schedule P-S WD-

T3 on October 1, 1990. This rate is 2.1 mills/kWh or $18.24/kW-year.

Nonfirm transmission service rate schedules using only the energy rate

have been implemented simultaneously with the firm transmission rates.

The LAP rates are developed using a cost-of-service methodology.

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.

Fryingpan-Arkansas Project--Comparison of 5-Year Rate Approval Period

[Revenues and expenses ($1,000)]

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

FY 1990 PRS-- Ratesetting

1994-98 PRS--1994-98 Difference

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

Total Revenues............. $73,165 $70,360 ($2,805)

============================================

Revenue Distribution:

Operations and

Maintenance........... 14,391 18,189 3,798

Purchased Power and

Transmission Expenses. 14,154 14,980 826

Interest............... 40,487 34,068 (6,419)

Investment Repayment... 4,133 3,123 (1,010)

Capitalized Expenses... 0 0 0

Prior-Year Adjustment.. 0 0 0

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

Total.............. 73,165 70,360 (2,805)

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

Basis for Rate Development--Loveland Area Projects

Firm Power

The P-SMBP PRS calculates the composite rate in mills/kWh for

future firm power (capacity and energy) sales. In the Fry-Ark PRS, the

study calculates the capacity rate in dollars per kW-year. The PRS

adjusts the selected rate until sufficient revenues are generated to

meet the cost-recovery requirement.

Transmission Service

The present rates were developed using a cost-of-service

methodology. Western's first step in this process is to determine the

projected use of the transmission system during the rate approval

period. Western reserves transmission for its own generating

capability, at plant, based on the Criteria and its transmission

commitments based on its transmission planning process.

The second step in designing the transmission rate is to determine

the estimated annual cost of operating, maintaining, and amortizing the

transmission system. Western considers two components in developing

this annual cost. The first is the annual O&M of the transmission

system. The second element is an investment annuity. The annuity is

used to determine the annual cost of amortizing the transmission system

over a 50-year repayment period.

The final step is to divide the costs by the commitments.

Comments

During the 91-day comment period, Western received four sets of

written questions or comments pertaining to this rate adjustment. In

addition, three persons commented during the August 30, 1993, public

comment forum. All comments were reviewed and considered in the

preparation of this rate order.

Written comments were received from the following sources:

Loveland Area Customer Association (COLORADO, WYOMING, KANSAS,

NEBRASKA)

Tri-State Generation and Transmission Association, Inc. (COLORADO,

WYOMING, NEBRASKA)

Kansas Electric Power Cooperative, Inc. (KANSAS)

Representatives of the following organizations made oral comments:

Loveland Area Customer Association (COLORADO, WYOMING, KANSAS,

NEBRASKA)

Tri-State Generation and Transmission Association (COLORADO, WYOMING,

NEBRASKA)

Kansas Electric Power Cooperative (KANSAS)

Comments received at the public meetings and in correspondence

dealt with controlling costs, interest rates and computations, division

of revenue requirements between P-SMBP Eastern and Western Divisions,

revision of Fry-Ark revenue requirements to reflect final cost

allocations, reallocation of energy returned from customers under the

Post-1989 allocations, future construction, financial integration of

Fry-Ark and Pick-Sloan, and a single transmission rate for both Eastern

and Western Divisions of the P-SMBP. Comments received that were

applicable to P-SMBP only were answered in the Record of Decision for

Rate Order No. WAPA-60. The comments and responses applicable to LAP,

paraphrased for brevity, are discussed below. Direct quotes from

comment letters are used for clarification where necessary.

Issue: Western received several comments concerned with escalating

O&M expenses and control of expenses in the future.

Response: Western recognizes the increases in O&M expenses and has

implemented cost-containment measures throughout the agency to review

expenses and budgets. Western presently maintains an open dialogue with

a customer group in P-SMBP-ED to inform them of progress being made and

to gain customer input for Western's planning process. Some Western

Division customers have participated in this interaction but the

majority do not. Western will extend the invitation to the Western

Division customer group to participate in the Eastern Division

interaction or provide a similar opportunity specifically for the

Western Division.

One commenter observed that O&M costs have increased at a rate that

is far greater than the Consumer Price Index (CPI). O&M expenses are

increasing due to inflation which is reflected in the CPI as well as

responding to programmatic and administrative requirements, such as

safety and environmental compliance. These expenses have been reviewed

both internally by Western and with power customer representatives.

Western continues to share the power customers' concerns with

Reclamation, and Western has received assurances that Reclamation will

participate in the cost-containment programs associated with O&M

functions. Western remains committed to cost-containment while striving

for efficiency and providing customer service. Western plans to

continue its O&M expense review process with power customers and

involve customer representatives in its cost-containment discussions.

Issue: One commenter suggested that Western should estimate the

long-term future interest rate in the PRS instead of using the current-

year rate.

Response: Western uses the rate required by DOE Order RA 6120.2,

sections 10.i. and 11.b., for all future investments. Section 10.i.

states that forecasts for PRSs will utilize the rate established by the

Secretary of the Treasury for the latest available year, and that this

rate shall be used for all future years. Section 11.b. defines the

criteria used by the Department of the Treasury to obtain the rate.

The present rate is computed on the basis of interest-bearing

Treasury securities which, at the time the computation is made, have

terms of 15 years or more to maturity. On this basis, short-term

fluctuations in market prices are removed and projections have built-in

stability based upon a ``rolling average'' each year. In effect,

volatile changes in the rate are mitigated through the blending

process.

While it is true that the rate may decrease in the FY 1994 PRS,

estimating a new rate would be no more accurate than the current method

for projecting investment rates 3 or 4 years into the future. In fact,

if such estimates were used in the late 1970's, they would have

resulted in higher revenue requirements. There is no assurance that

this would not happen again in the future.

Issue: Western received a comment that no interest credit is

provided annually in the PRS for the net cash balance accrued during

the year for interest expense that is not due and payable until

yearend. The commenter suggested that Western should revise its method

of computing interest offsets.

Response: The method used to compute interest in the PRS conforms

to DOE Order RA 6120.2, section 10.j., dated September 20, 1979, which

requires that interest shall be the sum of 1 year's interest on the

unpaid balance of each investment plus \1/2\ year's interest on new

investment added and in-service during the year, and interest on

deferred annual expenses (i.e., capitalized deficits). This amount may

be offset by a credit against interest expense if the credit concept is

utilized by the power marketing agency.

The methodology for computing the interest offset varies between

PMAs; DOE Order RA 6120.2 does not prescribe a specific procedure to be

used in making the interest calculation. The methodology employed by

Western incorporates an interest credit for \1/2\ year on all principal

payments made to investments during the current FY, and computes this

credit at the rates of the investments being repaid. No interest credit

is taken for interest collected and retained throughout the year.

This methodology is based on the premise that interest expenses are

equivalent to annual operating expenses such as O&M and are due and

payable throughout the year, not on the last day of the FY. As such,

payments to the Department of the Treasury are made to repay interest

as it is incurred. This approach is recommended by the U.S. General

Accounting Office (GAO) in attachment 3 to a letter dated September 8,

1983, from DOE to the Administrators of the five PMAs.

In attachment 3, GAO reviewed the interest rate practices of four

PMAs (Bonneville Power Administration, Southwestern Power

Administration, Western Area Power Administration, and Southeastern

Power Administration) and provided a draft recommendation that DOE

revise DOE Order RA 6120.2 to incorporate Western's methodology for

computing interest credits. GAO summarized that Western was utilizing

reasonable business principles in the application of the interest

credit.

Western believes that the methodology employed by the P-SMBP and

Fry-Ark PRSs is consistent with sound business and offers a fair and

reasonable credit against interest expenses.

Issue: It was suggested by one customer group that Western should

divide Pick-Sloan revenue requirements on the basis of capacity and

energy rather than energy alone, and that this be done on the basis of

total revenue requirements rather than the incremental basis presently

used.

Response: The different bases for the two marketing plans do not

readily permit an across-the-board comparison of the capacity available

from P-SMBP-WD and P-SMBP-ED. The LAO and BAO determined that the most

appropriate method to distribute costs was on the basis of contributed

energy from each division. This has permitted an ``apples-to-apples''

comparison of each division's resources while continuing to pool

resources and expenses.

The marketing plans of the P-SMBP-ED and the LAP were prepared

independently and take different approaches to the way that capacity is

marketed. In LAP, capacity is marketed on a fixed basis, with ``take-

or-pay'' amounts for monthly capacity. This capacity is marketed with

energy at less than the average customer load factor. P-SMBP-ED

marketed capacity on a proportional basis; that is, capacity is

marketed as a percentage of each customer's total monthly demand. This

method is commonly referred to as the ``X/Y'' method. Also, capacity

for the Eastern Division is marketed with ``load factor'' energy, with

any remaining resources being marketed as peaking capacity without

energy.

Western recognizes that there are numerous ways to market power,

divide expenses, compute available resources, and forecast future

impacts. The method chosen to share costs and revenues between the

Eastern and Western Divisions of P-SMBP is consistent with the

marketing criteria and represents a fair and equitable solution to the

customers of both areas. This decision was made with careful

consideration given to the relative contribution of resources,

investments, and expenses of each division to the total project.

Western does not propose to revise the allocation of firm power revenue

requirements for Eastern and Western Divisions in this rate adjustment.

Western will continue to observe its revenue-distribution methodology

to determine if future circumstances necessitate a change, and will

continue to work with the customers to address these concerns.

Issue: Two commenters requested that Western work with Reclamation

to adjust the power-related investment for the Fry-Ark in the PRS used

in the rate process.

Response: Regarding the level of investment for future projections,

Western believes that it is now appropriate to incorporate the approved

investment level in the PRS. While the figure in the final allocation

may not be exact (due to minor revisions in interest or adjustments to

the time that different investments were booked), Western believes that

the estimate is reliable as a basis for the future investment level.

Western has revised its PRS for Fry-Ark so that new revenue

requirements were determined and a new rate established for LAP. These

changes are incorporated in the first increment of the rate increase,

scheduled for February 1, 1994.

Western is continuing to work with Reclamation to bring the cost

allocation issue to a close. The final allocation was approved by

Reclamation's Assistant Commissioner for Resource Management on August

25, 1993, and Western will be working with Reclamation to reconcile

interest adjustments and obtain a schedule of investments for the

historical period. Until these items are completed, Western will not be

able to adjust financial statements or revise past interest expenses

and investments. Western has assured its customers that it will work

expeditiously with Reclamation to revise historical information.

Issue: Customers commented that the Western proposal to decrease

the amount of power used in the electric service rate calculation to

firm sales for LAP was inappropriate and that the power should be

reallocated, and that there were inconsistencies in the projected level

of power purchases.

Response: The resources identified in the Criteria were estimated

to be 717 MW of capacity and 2,088 GWh of energy. These resource

estimates identified as marketable energy with capacity are currently

used to calculate the LAP firm electric service rate. Because the

marketable resource estimates are greater than the amount of resource

under contract, LAP has incurred a $1.4 million annual shortfall in

revenue. To recover this amount, Western has proposed using the

resources under contract to calculate the rate rather than the

marketable resources. Western considers this reasonable and within its

rate design and power marketing authority.

The reallocation or other use of the difference between the

resources under contract and the marketable resources is an allocation

issue which has been discussed with the customers on numerous occasions

since the publication of the allocations. A summary of the most recent

Federal Register notice, which was published during the Public

Information Forum, was sent to the customers on September 17, 1993.

Western projected in the January 23, 1987, Federal Register notice

that it would be able to market 2,088 GWh of energy annually for firm

electric service. This was based on projected generation studies (based

on historical hydrology) less losses and project and special use loads;

actual historic generation was not used. This amounted to 2,335 GWh at

plant, less losses and project and special use. The difference referred

to is between 2,088 GWh, the estimated marketable energy, and the 2,040

GWh under contract which includes special use. That difference is 48

GWh. Most of this 48 GWh difference can be attributed to actual project

use amounts being higher than estimated amounts.

Western has continued to use the projected generation studies and

has published in the Federal Register a revised marketable energy level

of 2,124 GWh. That is, 2,355 GWh at plant (including Spirit Mountain),

less losses and project use. The apparent increase in the marketable

energy is 36 GWh. This is due to an additional resource (19.6 GWh from

Spirit Mountain), a change in losses (from 5 percent to 6 percent over

the system of Public Service Company of Colorado and from 7 percent to

6 percent over the LAP system), and the separation of project and

special use loads (special use is now treated as customer load).

This appears to be an 84 GWh increase in energy available for

reallocation (2,124 GWh less that amount of energy under contract, or

2,040 GWh). This was identified as available energy of 39,769 MWh in

the winter and 43,681 MWh in the summer in Western's September 17,

1993, letter.

Since the January 23, 1987, Federal Register notice, actual

operations have produced significantly less power than the projected

generation studies identified. Preliminary analysis of historic

generation reports have shown that the actual average generation less

losses and project use for the years 1960-89 has only produced an

average 2,020 GWh of marketable energy. This was derived from 2,241 GWh

at plant, less losses and project use. Therefore, LAP has an actual

generation deficit of 20 GWh, as compared to the amount of energy

currently under contract.

Since the implementation of the Criteria, Western has been able to

accommodate this deficit and the deficits caused by the recent drought

by purchasing power, bill crediting, net billing, shaping and storage,

interchange, and by drawing down the reservoirs. Also, some of

Western's firm electric service customers have not called upon their

full monthly capacity entitlements, which would cause a dramatic

increase in purchased energy to support this capacity.

Western will continue to honor its Post-1989 marketing commitment

under contract based upon the projected generation studies. The

Criteria also allows Western to revise the amounts of power committed

by contract based on the marketable resource in 1999. Western intends

to use actual average generation to identify the marketable resource

for the Post-1999 period. Western must notify customers of necessary

revisions to electric service contracts by 1996.

The actual average generation indicator, coupled with operational

flexibility and continued short-term drought-related costs, reinforces

Western's initial decision not to reallocate any projected increase in

energy identified in the projected generation studies. This action is

well within Western's discretionary authority. Western intends that

future rate design will use the resources under contract for firm

electric service rate calculations.

Issue: In a comment letter received from a customer association,

and in a package presented during the comment forum held on August 30,

1993, the customers questioned Western's criteria for participating in

rehabilitation/new construction projects. Specifically, they requested

that Western should limit its participation to those projects which can

be economically justified based on expected benefits. Also, the

customers requested that projected revenues or reduced purchased power

costs resulting from the construction be included in the PRS.

Response: Proposals for new facilities must first pass one of three

criteria before we will consider construction: increased revenues from

the new facility must exceed the annual cost, or customers must benefit

sufficiently to support the project in spite of a possible rate

increase, or the project will be funded from non-Federal sources. We

will continue our construction program as necessary to ensure we

provide reliable service.

Issue: One party commented that since Western has contractually and

operationally integrated the resources from Fry-Ark and P-SMBP-WD, we

should integrate the two projects financially as well. The same party

commented that it is unclear whether Fry-Ark properly shares in the

financial benefits it contributes to LAO operations.

Response: The two projects were created by separate congressional

legislation and therefore require separate financial accounting. The

only way Western would be able to completely integrate the two projects

would be if Congress passed new legislation mandating that the two

projects be combined.

Western has also kept the projects financially separate because of

the nature of the projects themselves. Eastern Division facilities are

governed by the flow on the main-stem of the Missouri River and receive

no benefit from the operation of Fry-Ark, and Western Division

facilities rely on Fry-Ark pumped-storage capacity to ``firm up''

regular sales. This is particularly important for the Western Division

during drought conditions because its reservoirs are small and have

minimal carryover storage. In addition, Western is a member of the

Rocky Mountain Generation Cooperative (RMGC). The Western Division uses

the pumped-storage features of Fry-Ark as a shaping and storage device

for RMGC sales on a reimbursable basis. This hydro-thermal integration

benefits all members of RMGC, and subsequently Western's customers, and

makes the most efficient use of the generating facilities.

As for the financial credits received by Fry-Ark as a part of the

LAP system, Western has gone to great lengths to ensure that Fry-Ark

receives an equitable share of LAP revenues. Revenues that are clearly

identifiable to either Fry-Ark (e.g., third-party sales of capacity

over the system of the Public Service Company of Colorado) or P-SMBP-WD

(e.g., transmission of supplemental power to customers over Western's

system in Nebraska and Wyoming) are directly credited to those

projects. Revenues not identifiable to either of the projects are

divided on the basis of the proportional revenue requirements of each

project, as specified in the Post-1989 Power Marketing Plan.

The division of general revenues is not a simple process because

the products of the Western Division and Fry-Ark are so different. To

divide general sales revenues on the basis of energy would not be fair

to Fry-Ark because it produces proportionately much less than the

Western Division. To divide revenues on the basis of capacity would not

be appropriate either because most of Fry-Ark's capacity has no energy

associated with it. Western believes that the present approach of

dividing LAP revenues between the projects is reasonable because of the

way they are operated together in the system. The operational and

contractual integration of the two projects was conducted according to

the required public process and performed in an open and cooperative

manner with Western's customers. No plans are being made to change the

apportionment of revenues between the two projects.

Issue: The customers suggested that since all the investment in P-

SMBP is integrated financially, a transmission rate based only on the

P-SMBP-WD costs is inconsistent with the allocation of investment,

related O&M expenses, and associated revenue credits between divisions.

Response: It would be inappropriate to completely integrate the

projected expenses, revenues, and commitments for the Eastern and

Western Divisions of the P-SMBP into a single transmission rate. Even

though the related revenues and expenses assigned to P-SMBP are

combined into a single P-SMBP PRS, they are two separate and very

different systems electrically, physically, and politically. The United

States and a portion of Canada are divided into separate transmission

zones to control inadvertent flow. Due to difficulties in maintaining

AC interconnections between the East and West, a series of AC-DC-AC

converter stations have been constructed to electrically separate one

system from the other. The dividing line for the Pick-Sloan Eastern and

Western Divisions coincides with this electrical division line. Each

system is also controlled separately from dispatch offices located in

Watertown, South Dakota (Eastern Division), and Loveland, Colorado

(Western Division).

Politically, the two areas are governed by two different Councils

of the North American Electric Reliability Council. The Eastern

Division is a part of the Mid-Continent Area Power Pool while the

Western Division is governed by the Western Systems Coordinating

Council.

Environmental Evaluation

In compliance with the National Environmental Policy Act of 1969,

42 U.S.C. 4321 et seq.; Council on Environmental Quality Regulations

(40 CFR parts 1500-1508); and DOE NEPA Regulations (10 CFR Part 1021),

Western has determined that this action is categorically excluded from

the preparation of an environmental assessment or an environmental

impact statement.

Executive Order 12866

DOE has determined that this is not a significant regulatory action

because it does not meet the criteria of Executive Order 12866, 58 FR

51735. Western has an exemption from centralized regulatory review

under Executive Order 12866; accordingly, no clearance of this notice

by the Office of Management and Budget is required.

Availability of Information

Information regarding this rate adjustment, including PRSs,

comments, letters, memorandums, and other supporting material made or

kept by Western for the purpose of developing the power rates, is

available for public review in the Loveland Area Office, Western Area

Power Administration, Office of the Assistant Area Manager for Power

Marketing, 5555 East Crossroads Boulevard, Loveland, CO 80538-8986;

Western Area Power Administration, Division of Marketing and Rates,

1627 Cole Boulevard, Golden, Colorado 80401; and Western Area Power

Administration, Office of the Assistant Administrator for Washington

Liaison, room 8G-061, Forrestal Building, 1000 Independence Avenue SW.,

Washington, DC 20585.

Submission to Federal Energy Regulatory Commission

The rates herein confirmed, approved, and placed into effect on an

interim basis, together with supporting documents, will be promptly

submitted to FERC for confirmation and approval on a final basis.

Order

In view of the foregoing and pursuant to the authority delegated to

me by the Secretary of Energy, I confirm and approve on an interim

basis, effective February 1, 1994, Rate Schedules L-F3, L-T3, and L-T4

for the Loveland Area Projects. These rate schedules shall remain in

effect on an interim basis, pending Federal Energy Regulatory

Commission confirmation and approval of them or substitute rates on a

final basis, through January 31, 1999.

Issued in Washington, DC, January 6, 1994.

Bill White,

Deputy Secretary.

United States Department of Energy--Western Area Power Administration

[Rate Schedule L-F4 (Supersedes Schedule L-F3)]

Loveland Area Projects Colorado, Kansas, Nebraska, Wyoming;

Schedule of Rates for Firm Power Service

Effective: First Step: Beginning on the first day of the first

full billing period on or after February 1, 1994, through September

30, 1994. Second Step: Beginning on the first day of the first full

billing period on or after October 1, 1994, through January 31,

1999.

Available: Within the marketing area served by the Loveland Area

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

First Step

Demand Charge: $2.65 per kilowatt (kW) of billing demand.

Energy Charge: 10.33 mills per kilowatthour (kWh) 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 in excess of, the delivery obligation under the power

sales contract, or (2) the contract rate of delivery.

Second Step

Demand Charge: $2.85 per kW of billing demand.

Energy Charge: 10.85 mills per kWh 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 in excess of, the delivery obligation under the power

sales contract, or (2) the contract rate of delivery.

Adjustments

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.

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.

United States Department of Energy--Western Area Power Administration

[Rate Schedule L-T3 (Supersedes Schedule L-T1)]

Loveland Area Projects Colorado, Kansas, Nebraska, Wyoming;

Schedule of Rate for Firm Transmission Service

Effective: The first day of the first full billing period

beginning on or after February 1, 1994, through January 31, 1999.

Available: Within the marketing area served by the Loveland Area

Projects (LAP).

Applicable: To firm transmission service customers where power

and energy are supplied to the LAP system at points of

interconnection with other systems and transmitted and delivered,

less losses, to points of delivery on the LAP system specified in

the service contract.

Character and Conditions of Service: Transmission service for

three-phase alternating current at 60 hertz, delivered and metered

at the voltages and points of delivery specified in the service

contract.

Rate

Transmission Service Charge: $22.52 per kilowatt (kW) per year

for each kilowatt delivered at the point of delivery, as specified

in the service contract, payable monthly at the rate of $1.88 per

kW. For those customers with existing contracts utilizing an energy

rate, the rate will be 2.6 mills per kilowatthour.

Adjustments

For Reactive Power

None. There shall be no entitlement to transfer of reactive

kilovoltamperes at delivery points, except when such transfers may

be mutually agreed upon by contractor and contracting officer or

their authorized representatives.

For Losses

Power and energy losses incurred in connection with the

transmission and delivery of power and energy under this rate

schedule shall be supplied by the customer in accordance with the

service contract.

United States Department of Energy--Western Area Power Administration

[Rate Schedule L-T4 (Supersedes Schedule L-T2)]

Loveland Area Projects Colorado, Kansas, Nebraska, Wyoming;

Schedule of Rate for Nonfirm Transmission Service

Effective: The first day of the first full billing period

beginning on or after February 1, 1994, through January 31, 1999.

Available: Within the marketing area served by the Loveland Area

Office.

Applicable: To nonfirm transmission service customers where

power and energy are supplied to the Loveland Area Projects (LAP)

system at points of interconnection with other systems and

transmitted and delivered subject to the availability of

transmission capacity, less losses, to points of delivery on the LAP

system specified in the service contract.

Character and Conditions of Service: Transmission service on an

intermittent basis for three-phase alternating current at 60 hertz,

delivered and metered at the voltages and points of delivery

specified in the service contract.

Rate

Transmission Service Charge: 2.6 mills per kilowatthour (kWh)

delivered at the point of delivery for each kWh scheduled, payable

monthly.

Adjustments

For Reactive Power

None. There shall be no entitlement to transfer of reactive

kilovoltamperes at delivery points, except when such transfers may

be mutually agreed upon by contractor and contracting officer or

their authorized representatives.

For Losses

Power and energy losses incurred in connection with the

transmission and delivery of power and energy under this rate

schedule shall be supplied by the customer in accordance with the

service contract.

[FR Doc. 94-1486 Filed 1-19-94; 4:15 pm]

BILLING CODE 6450-01-P