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

DEPARTMENT OF ENERGY

Pick-Sloan Missouri Basin Program-Eastern Division--Notice of

Rate Order No. WAPA-60

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of Rate Order--Pick-Sloan Missouri Basin Program-Eastern

Division (P-SMBP-ED) firm electric service rate adjustment.

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

Secretary of the Department of Energy (DOE) of Rate Order No. WAPA-60

and Rate Schedules P-SED-F6 and P-SED-FP6 placing increased firm power

and firm peaking power rates for the P-SMBP-ED into effect on an

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

remain in effect on an interim basis until the Federal Energy

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

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

comparison of existing and provisional rates follows:

Eastern Division Provisional Rate Changes

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Provisional rates February 1, Provisional rates October 1,

Type of service Existing rates 1994, and percent change 1994, and percent change

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FIRM COMMERCIAL:

Composite Rate...................................... 12.16 (mills/kWh)............. 13.31 (mills/kWh) 9.5%........ 14.23 (mills/kWh) 7.0%.

Firm Energy......................................... 7.09 (mills/kWh).............. 7.76 (mills/kWh) 9.5%......... 8.32 (mills/kWh) 7.2%.

Firm Capacity....................................... $2.74/kW-month................ $3.00/kW-month, 9.5%.......... $3.20/kW-month 6.7%.

Tiered > 60 percent L.F............................. 3.38 (mills/kWh).............. 3.38 mills/kWh................ 3.38 mills/kWh.

Firm Peaking:

Peaking Capacity.................................... $2.74/kW-month................ $3.00/kW-month, 9.5%.......... $3.20/kW-month, 6.7%.

Peaking Energy...................................... 7.09 mills/kWh................ 7.76 (mills/kWh) 9.5%......... 8.32 (mills/kWh) 7.2%.

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DATES: Rate Schedules P-SED-F6 and P-SED-FP6 will be placed into effect

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

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

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

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

superseded.

FOR FURTHER INFORMATION CONTACT:

Mr. James D. Davies, Area Manager, Billings Area Office, Western

Area Power Administration, P.O. Box 35800, Billings, MT 59107-5800,

(406) 657-6532;

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

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

3398, (303) 231-1545;

Mr. Joel Bladow, Assistant Administrator for Washington Liaison,

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

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

5581.

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

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

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

transmission rates on a nonexclusive basis to the Administrator of

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

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

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

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

rates to FERC. Existing DOE procedures for public participation in

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

18, 1985 (50 FR 37835).

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

DOE Organization Act, 42 U.S.C. 7152(a), through which the power

marketing functions of the Secretary of the Interior and the Bureau of

Reclamation (Reclamation) under the Reclamation Act of 1902, 43 U.S.C.

371 et seq., as amended and supplemented by subsequent enactments,

particularly section 9(c) of the Reclamation Project Act of 1939, 43

U.S.C. 485h(c), and other acts specifically applicable to the project

system involved, were transferred to and vested in the Secretary of

Energy (Secretary).

Discussions on the proposed rate adjustments were initiated on

January 26, 1993, when a letter announcing the preliminary informal

customer meetings was mailed to all firm power customers and other

interested persons. These meetings were conducted at four different

locations on February 5, 8, 9, and 10, 1993. At these preliminary

meetings, Western representatives explained the need for the rate

increases and answered questions from those attending.

The consultation and comment period was initiated on July 8, 1993,

with publication of a Federal Register notice (58 FR 36684) that

officially announced the proposed rate adjustments and procedures for

public participation. The Federal Register notice announced a series of

public information forums that were held on July 20, and August 9-11,

1993, in Northglenn, Colorado; Sioux Falls, South Dakota; Fargo, North

Dakota; and Billings, Montana. Public comment forums were held in

Northglenn, Colorado, and Sioux Falls, South Dakota, on August 30 and

31, 1993, respectively. The consultation and comment period concluded

October 6, 1993.

During the comment period, Western received 10 comment letters on

the Pick-Sloan Missouri Basin Program (P-SMBP) rate adjustment. At the

August 30 and 31, 1993, public comment forums, one person commented

orally. All comments were considered in preparation of the rate order.

Western has concluded that the P-SMBP rate adjustments are needed to

meet cost-recovery criteria.

The proposed rate adjustments are based upon the fiscal year (FY)

1992 power repayment study (PRS). To prepare the ratesetting PRS,

Western considered projections which will be used in the final FY 1993

PRS. Western's objective is to mitigate the rapidly increasing deficits

due to reduced surplus sales revenue and increasing purchased power

expense resulting from the drought on the P-SMBP. Using this concept,

Western developed a two-step rate adjustment. The first step is based

upon the FY 1992 PRS with 5 future years of purchased power expense and

1 future year of reduced surplus sales revenue. The second step is

based on the FY 1992 PRS utilizing 5 years of projected increased

purchased power expense and reduced surplus sales revenue for 1 year.

In the second step, Western also included expected increases in

operations and maintenance (O&M) expenses and 1 additional year of

power investment. By implementing this two-step rate adjustment,

Western is providing P-SMBP customers with a more accurate basis for

budgeting their future power costs as well as mitigating the impact of

the rate increases.

In Rate Order No. WAPA-60, results of the ratesetting PRS are being

compared to the FY 1990 PRS, which was the basis for the existing P-

SMBP rates. The comparison shows the following differences:

1. The projected O&M expenses, including the integrated projects,

for the 100-year period have increased a total of $10.2 million per

year.

2. Purchased power projected over the future 6-year period is $113

million. These costs are partially attributable to the extended drought

which necessitated the Bureau of Reclamation and the Corp of Engineers

to draw down the reservoirs to an extremely low level. This has caused

Western to project future purchased power expenses for the next few

years until the reservoirs are full again. Although FY 1993 was an

above-average water year, purchased power expenses are continuing to be

projected because the flooding in the Midwest severely restricted water

releases and therefore severely curtailed power generation.

3. Reduced surplus sales and increased purchased power costs

appearing historically in the study, as a result of the drought in the

Missouri Basin, have now accumulated $126 million in unpaid annual

expenses, which have been capitalized. These and expected unpaid annual

expenses over the next 2 years are projected to be repaid by 2002.

4. The power investments projected over the future 6-year period

are $286 million. New power investments, other than replacements, are

not projected beyond the 6-year period.

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

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

capitalized unpaid annual expenses. The second greatest impact comes

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

responding to programmatic and administrative requirements, such as

safety programs and environmental compliance.

Rate Order No. WAPA-60, confirming, approving, and placing the

proposed P-SMBP-ED rate adjustments into effect on an interim basis, is

issued, and the new Rate Schedules P-SED-F6 and P-SED-FP6 will be

submitted promptly to FERC for confirmation and approval on a final

basis.

Issued in Washington, DC, January 6, 1994.

Bill White,

Deputy Secretary.

Order Confirming, Approving, and Placing the Pick-Sloan Missouri Basin

Program-Eastern Division Firm Power Service Rates Into Effect on an

Interim Basis

In the matter of: Western Area Power Administration Rate

Adjustments for Pick-Sloan Missouri Basin Program-Eastern Division,

Rate Order No. WAPA-60

January 6, 1994.

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

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

which the power marketing functions of the Secretary of the Interior

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

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

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

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

applicable to the Pick-Sloan Missouri Basin Program (P-SMBP), were

transferred to and vested in the Secretary of Energy.

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

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

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

nonexclusive basis to the Administrator of the Western Area Power

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

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

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

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

Federal Energy Regulatory Commission. Existing DOE procedures for

public participation in power rate adjustments (10 CFR part 903) became

effective on September 18, 1985 (50 FR 37835).

Acronyms and Definitions

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

apply:

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

month).

BAO: Western's Billings Area Office.

Corps: U.S. Army Corps of Engineers.

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

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

(January 31, 1986) and Eastern Division Pick-Sloan Missouri Basin

Program Final Post-1985 Marketing Plan, 45 FR 71860 (October 30,

1980).

CROD: Contract Rate of Delivery.

Customer Brochure: A document prepared for public distribution

explaining the background of the rate proposal contained in this

rate order.

DOE: Department of Energy.

DOE Order RA 6120.2: An order dealing with power marketing

administration financial reporting.

FERC: Federal Energy Regulatory Commission.

Fry-Ark: Fryingpan-Arkansas Project.

FY: Fiscal year.

Interior: U.S. Department of the Interior.

kW: Kilowatt.

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

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

contract rate of delivery.

kWh: Kilowatthour.

LAO: Western's Loveland Area Office.

LAP: Loveland Area Projects.

M&I: Municipal and industrial.

mills/kWh: Mills per kilowatthour.

MW: Megawatt.

O&M: Operation and maintenance.

pinch-point: The FY in which the level of the rate is set as

dictated by a revenue requirement in that future year to meet

relatively large annual costs or to repay investments which come

due.

PMA: Power marketing administration.

PRS: Power repayment study.

P-SED-F5: Pick-Sloan Eastern Division's existing rate schedule for

firm power service.

P-SED-F6: Pick-Sloan Eastern Division's provisional rate schedule

for firm power service.

P-SED-FP5: Pick-Sloan Eastern Division's existing rate schedule for

firm peaking service.

P-SED-FP6: Pick-Sloan Eastern Division's provisional rate schedule

for firm peaking service.

P-SMBP: Pick-Sloan Missouri Basin Program.

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

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

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

Treasury: Secretary of the Department of the Treasury.

Western: Western Area Power Administration, U.S. Department of

Energy.

Effective Date

The new rates will become effective on an interim basis on the

first day of the first full billing period beginning on or after

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

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

until superseded.

Public Notice and Comment

The procedures for public participation in power and transmission

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

Western in the development of these firm power rates. These firm power

rates represent an increase of more than 1 percent in total P-SMBP-ED

revenues; therefore, it is a major rate adjustment as defined at 10 CFR

903.2(e) and 903.2(f)(1). The distinction between a minor and a major

rate adjustment is used only to determine the public procedures for the

rate adjustment.

The following summarizes the steps Western took to ensure

involvement of interested parties in the rate process:

1. Discussion of the proposed rate adjustments was initiated on

January 26, 1993, when a letter announcing informal customer meetings

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

The 1993 meetings were held on the following dates: February 5 in

Billings, Montana; February 8 in Sioux Falls, South Dakota; February 9

in Denver, Colorado; and February 10 in Fargo, North Dakota. At these

informal meetings, Western representatives explained the need for the

increase and answered questions from those attending.

2. On March 9, 1993, a customer brochure was mailed to all

customers and other interested persons. This mailing also included a

letter announcing the four public information forums and two comment

forums.

3. On March 11, 1993, a letter was mailed to all customers and

other interested persons on the delay of the publishing of the Federal

Register notice. The public information forums and comment forums were

also delayed.

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

36684), officially announcing the proposed firm power rate adjustments,

initiating the public consultation and comment period, announcing the

information and comment forums, and presenting procedures for

participation.

5. On July 14, 1993, letters were mailed to all P-SMBP-ED customers

and interested persons announcing the publication of the Federal

Register notice of July 8, 1993. This mailing also included a letter

announcing four public information forums and two comment forums.

6. The public information forums were conducted on the following

dates: July 20 in Northglenn, Colorado; August 9 in Billings, Montana;

August 10 in Sioux Falls, South Dakota; and August 11 in Fargo, North

Dakota. At these forums, Western representatives explained the need for

the rate increases in greater detail and answered questions.

7. Western received an extensive request for information from one

customer group. We responded by providing data and background

information for the ratesetting PRS.

8. The comment forums were held on August 30, 1993, at Northglenn,

Colorado, and August 31, 1993, at Sioux Falls, South Dakota, to give

the public an opportunity to comment for the record. One person

representing a customer and customer group made oral comment at the

August 30, 1993, forum. Western received no comments at the August 31,

1993, forum.

9. Ten comment letters were received during the 91-day consultation

and comment period. The consultation and comment period ended October

6, 1993. All formally submitted comments have been considered in the

preparation of this rate order.

Project History

The initial stages of the Missouri River Basin Project were

authorized by section 9 of the Flood Control Act of 1944 (58 Stat. 877,

891). The Missouri River Basin Project, later renamed the P-SMBP to

honor its two principal authors, has been under construction since

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

navigation improvement, irrigation, M&I water development, and

hydroelectric production for the entire Missouri River Basin.

Multipurpose projects have been developed on the Missouri River and

its tributaries in Colorado, Montana, Nebraska, North Dakota, South

Dakota, and Wyoming.

Power Repayment Studies

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

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

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

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

12b, requires that:

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

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

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

of power investment at Federal hydroelectric generating plants

within 50 years after they become revenue producing, except as

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

Federal transmission investment within the average service life of

such transmission facilities or within a maximum of 50 years,

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

of property of a Federal power system within its expected service

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

irrigation investment within the period established for the

irrigation water users to repay their share of construction costs;

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

projects, or States.

Existing and Provisional Rates

Eastern Division

The existing firm power rates and the provisional firm power rates

necessary to meet the revenue requirements for the P-SMBP-ED are listed

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

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

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

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

billing period beginning on or after October 1, 1994.

A comparison of the existing and provisional rates follows:

Eastern Division Provisional Rate Changes

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Provisional rates, Provisional rates,

Type of service Existing rates February 1, 1994 October 1, 1994

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

Firm Power Service Rate Schedule:

Composite Rate................ 12.16 mills/kWh\1\...... 13.31 mills/kWh\2\...... 14.23 mills/kWh.\2\

Firm Capacity................. $2.74/kW-month\1\....... $3.00/kW-month\2\....... $3.20/kW-month.\2\

Firm Energy................... 7.09 mills/kWh\1\....... 7.76 mills/kWh\2\....... 8.32 mills/kWh.\2\

Tiered > 60 percent L.F....... 3.38 mills/kWh\1\....... 3.38 mills/kWh\2\....... 3.38 mills/kWh.\2\

Firm Peaking Power Service Rate

Schedule:

Peaking Capacity.............. $2.74/kW-month\3\....... $3.00/kW-month\4\....... $3.20/kW-month.\4\

Peaking Energy................ 7.09 mills/kWh\3\....... 7.76 mills/kWh\4\....... 8.32 mills/kWh.\4\

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

\1\P-SED-F5.

\2\P-SED-F6.

\3\P-SED-FP5.

\4\P-SED-FP6.

Western Division

The LAP rate will be designed to recover the P-SMBP-WD revenue

requirements for P-SMBP and the revenue requirements for Fry-Ark. The

adjustment to the LAP rates is a separate formal procedure which is

documented in Rate Order No. WAPA-61. Rate Order No. WAPA-61 is also

scheduled to go into effect on the first day of the first full billing

period beginning on or after February 1, 1994. The LAP rates will yield

the revenue requirements for FY 1994-98 for the P-SMBP-WD.

Certification of Rate

Western's Administrator has certified that the P-SMBP-ED firm power

rates placed into effect on an interim basis herein are the lowest

possible consistent with sound business principles. The rates have been

developed in accordance with administrative policies and applicable

laws.

Discussion

Although the P-SMBP is considered a single entity for financial and

repayment purposes, the power generated by the P-SMBP is marketed in

two separate and distinct areas. These are known as the Eastern

Division and the Western Division, and each has its own marketing plan

and method of designing rates to collect required revenue from power

sales.

The existing and provisional revenue requirements for the Eastern

and Western Divisions for the P-SMBP are as follows:

P-SMBP Firm and Peaking Revenue Requirement

[In millions]

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

First Second

adjustment adjustment

Current February October

1994 1994

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

Eastern Division Firm Commercial. $103.1 $112.9 $120.8

Eastern Division Peaking......... 12.3 13.5 14.4

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

Total Eastern Division

Revenue Requirement....... $115.4 $126.4 $135.2

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

Western Division Firm Commercial. 28.0 30.3 31.4

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

Total P-SMBP Firm and

Peaking Revenue

Requirement............... $143.4 $156.7 $166.6

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

The revenue increases are necessary to satisfy the cost-recovery

criteria set forth in DOE Order RA 6120.2.

Statement of Revenue and Related Expenses

The following table provides a summary of revenue and expense data

through the 5-year provisional rate approval period.

Pick-Sloan Missouri Basin Program--Comparison of 5-Year Rate Approval

Period

[Revenues and Expenses ($1,000)]

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

FY 1990 PRS Ratesetting

1994-98 PRS 1994-98 Difference

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

Total Revenues................... $1,064,628 $1,199,151 $134,523

Revenue Distribution:

O&M.......................... $540,919 $678,407 $137,488

Purchased Power.............. 9,300 75,000 65,700

Interest..................... 307,913 422,954 115,041

Investment Repayment......... 143,233 53,363 (89,870)

Capitalized Expenses......... 0 (30,573) (30,573)

Integrated Projects.......... 63,263 0 (63,263)

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

Total.................... $1,064,628 $1,199,151 $134,523

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

Basis for Rate Development--P-SMBP-ED

The P-SMBP-ED rates were designed to continue to maintain an

approximate 50/50 split between revenue earned from the demand and

energy charges as a basis for the rate design. The revenue yield will

vary among customers because of a customer's individual load

characteristics.

The interim rates contain a $3.00/kW-month firm capacity charge and

a 7.76 mills/kWh firm energy charge in FY 1994 which will yield the

necessary revenue for the first year of the rate-approval period,

effective on the first day of the first full billing period on or after

February 1, 1994. To provide the additional necessary revenue, an

increase to $3.20/kW-month firm capacity charge and an 8.32 mills/kWh

firm energy charge will be in effect on the first day of the first full

billing period beginning on or after October 1, 1994. The rate-approval

period terminates on January 31, 1999.

Comments

During the 91-day comment period, Western received 10 letters

containing written comments pertaining to this rate adjustment. In

addition, one person representing a group of customers commented during

the August 30, 1993, public comment forum. We received no comments at

the August 31, 1993, forum. All comments were reviewed and considered

in the preparation of this rate order.

Written comments were received from the following sources:

Loveland Area Customer Association (Colorado, Wyoming, Kansas,

Nebraska)

Tri-State Generation and Transmission Association, Inc. (CO, WY, NE)

City of Litchfield (Minnesota)

Lower Brule Sioux Tribe (South Dakota)

Nebraska Public Power District (Nebraska)

City of Lincoln (Nebraska)

Missouri Basin Municipal Power Agency (SD, ND, MN, and IA)

Basin Electric Power Cooperative (ND, SD, MN, IA, MT, WY, and CO)

East River Electric Power Cooperative (South Dakota)

A representative of the following organizations made an oral

comment:

Loveland Area Customer Association

Tri-State Generation and Transmission Association, Inc.

Comments received at the public meetings and in correspondence

dealt with controlling costs, Eastern Division firm peaking power rate

design, and projections of revenue and expenses. The comments and

responses, paraphrased for brevity, are discussed below. Direct quotes

from comment letters are used for clarification where necessary.

Issue: Customers suggested that Western should not participate in

new transmission projects whose cost will affect firm power rates,

unless the facilities are needed to reliably meet its firm power

obligations or the facilities will result in net financial savings to

the firm power revenue requirement.

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

criteria before we will consider construction: increased revenues from

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

sufficiently to support the project in spite of a possible rate

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

will continue our construction program as necessary to ensure we

provide reliable service.

Issue: Customers are concerned with the rate at which O&M expenses

have increased and are projected to increase in the PRS.

Response: Western received several comments concerned with

controlling costs related to O&M expenses. One recognized that costs

appear to be supportable, one asked for mitigation of the rate impact,

and one suggested an opportunity for review and comment on expenditures

of Western, the Bureau, and the Corps. Presently, Western has such an

interaction with the customer group in the Eastern Division of Pick-

Sloan. This comment is from a Western Division customer group. There

are several Western Division customers who do participate in the

Eastern Division interaction; the majority of the Western Division

customer group do not. We propose to extend an invitation to the

Western Division customer groups to participate in the Eastern Division

interaction or we will provide a similar opportunity specifically for

the Western Division.

One commenter observed that P-SMBP O&M costs have increased at a

rate that is far greater than the Consumer Price Index (CPI). O&M

expenses are increasing due to inflation which is reflected in the CPI

as well as responding to programmatic and administrative requirements,

such as safety and environmental compliance. These expenses have been

reviewed both internally by Western and with power customer

representatives. Western continues to share the power customers'

concerns with Reclamation and the Corps and has received assurances

from each agency that each will participate in the cost-containment

programs associated with O&M functions. Western remains committed to

cost containment while striving for efficiency and providing customer

service. Western plans to continue its O&M expense review process with

power customers and involve customer representatives in its cost-

containment discussions.

Issue: Customers of firm peaking power have stated that the Eastern

Division firm peaking rate is arbitrary, unfair, and discriminatory in

light of the type of service provided by this commodity.

Response: We received comments from two customers expressing this

concern. They observed that the capacity charge for firm peaking is

keyed to the seasonal CROD. That is, the firm peaking customers pay for

the capacity reserved for them in each month as opposed to the method

used for the firm commercial customers who pay only for the maximum

capacity delivered to them each month. They questioned the cost of

providing capacity for peaking customers vs. firm commercial customers.

Logic tells us that the costs for providing or reserving capacity

in the system are the same for each class of service. If we were to

assume that all fixed costs in a hydro-based system are to be recovered

by the capacity charge, and since hydro-based systems do not have fuel

costs, the purchased energy costs are the only variable costs to be

recovered by the energy charge. This means that the firm commercial and

firm peaking capacity charge must recover all costs except the

purchased energy costs which are to be recovered by the energy charge.

Western traditionally recovers 50 percent of its firm revenue

requirements from capacity charges and 50 percent from the energy

charges. Western has chosen this methodology to balance the impact of

allocating the costs for firm service between customers with a high

load factor and customers with a low load factor.

We received comments from a customer supporting the present rate

design for peaking capacity. One customer stated that they were

satisfied with the peaking product, but urged Western in its FY 1995

rate review process to revise its methodology of applying the rate to

peaking service. In interactions between peaking customers and Western,

we have discussed several options to make the peaking product more

flexible to better meet the customers' needs. Many of the options

discussed would have added more costs to providing the product or

limited the flexibility of the P-SMBP generating system and, therefore,

could not be supported by Western.

Western is not changing the peaking rate methodology at this time.

However, in the next rate adjustment, we will consider other methods of

applying the peaking rate or modifying the product.

Issue: Several customers commented that the second adjustment

should not be implemented by this rate adjustment process and a second

rate adjustment process should be performed next year after more facts

are known.

Response: In discussions with various customer groups prior to this

rate adjustment process, we were urged to find a method to limit the

number of times we proceed through the rate process. This two-step

process reduces both Western's and its customers' expense associated

with proceeding through multiple rate adjustment processes. Our

response to this request is to determine the first rate and project the

second step. Therefore, assuming our projections are accurate, we will

have saved the expense of one of two rate adjustment processes. Even

though we do not expect to process a rate adjustment in the second

year, we will test our rate and our assumptions in the second year. If

the projection falls short of repaying the cost of the project, in

accordance with DOE Order RA 6120.2, we would initiate a rate

adjustment process. This calls for the question, ``What if the rate is

too high in the second year?'' The P-SMBP has capitalized $126 million

of annual expenses through the end of FY 1992. Until that amount is

repaid, revenues which are surplus to the immediate annual needs of the

project will be applied to these deficits.

This two-step rate adjustment has allowed Western's customers to

better budget and provides a longer-term planning window. When Western

is not processing a rate adjustment, Western shares the results of its

annual PRS and supporting data with its customer groups and thoroughly

reviews the underlying assumptions and results.

For these reasons, Western is proceeding with the two-step rate

adjustment.

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

divide Pick-Sloan revenue requirements between the Eastern and Western

Divisions on the basis of the firm capacity and energy of each Division

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

total revenue requirements rather than the incremental basis presently

used.

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

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

from P-SMBP-WD and P-SMBP-ED. It was determined by LAO and BAO that the

most appropriate method to distribute costs was on the basis of

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

to-apples'' comparison of the relative contribution of each division's

resources while continuing to pool resources and expenses.

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

independently and take different approaches to the way that capacity is

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

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

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

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

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

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

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

any remaining capacity resources being marketed as peaking capacity

without energy.

Western recognizes that there are numerous ways to market power,

divide expenses, compute available resources, and forecast future

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

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

marketing criteria and represents a fair and equitable solution to the

customers of both areas. This decision was made with careful

consideration given to the relative contribution of resources,

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

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

requirements for Eastern and Western Divisions in this rate adjustment.

Western will continue to observe its revenue-distribution methodology

to determine if future circumstances necessitate a change, and will

continue to work with customers to better understand and address these

concerns.

Issue: Several customers commented that Western's proposal to

decrease the amount of firm sales used in the electric service rate

calculation for LAP was inappropriate and that amount should be

reallocated, and that there were inconsistencies in the projected level

of power purchases.

Response: This issue is applicable only to LAP and, accordingly, is

discussed in Rate Order No. WAPA-61.

Issue: Several customers commented that Western's provisional firm

power rate is too high.

Response: Several individual customer comments requested mitigation

of the rate and one customer indicated that although the rate

adjustments are significant, the adjustments were understandable and

supportable. A customer group commented that the firm power rate was

overstated and pointed to several areas where either expense

projections should be reduced or projections of revenues should be

increased. We have addressed each of the identified areas as a separate

issue, and the decision on each is reflected in the response.

Issue: Western could reduce its purchased power projection by

utilizing the hydrology projections to forecast purchased power

requirements.

Response: Western uses hydrology projections coupled with

historical experience to project purchased power expense. This

projection has been increasingly difficult to do in recent years

because of the drought, as well as the ensuing flood and the endangered

species operating restrictions. We have found that the purchased power

expense can be underestimated when the hydrology projections alone are

used to project purchased power expense. If Western had ignored

historical purchased power trends and used only hydrology projections

to forecast purchased power, we would have again underestimated that

expense. There was so much water downstream, causing the floods in the

Midwest, the P-SMBP water releases were greatly curtailed, thus

reducing its generating ability. Western will continue to review its

projection methods as suggested. The purchased power projection in this

study, which uses a combination of factors, follows the historical

trend better than the projection utilizing the hydrology data alone;

therefore, Western is not revising the projections at this time.

Issue: Western should update its generation projections to reflect

the storage condition incurred as a result of the above-average inflows

for FY 1993.

Response: The Corps is presently preparing and revising generation

projections for this very reason. Those projections will be used in

preparing the next FY's PRS. At that time we will also have a record of

the additional costs incurred and reduced generation in FY 1993 as a

result of flood mitigation accomplished by reduced water releases from

the dams on the Pick-Sloan Missouri Basin System. We believe it is

premature to revise only the generation projections without considering

all impacts to the system. The generation projections in the

ratesetting study correspond to the budget projections used in that

study. The next year's PRS will consider all of these effects. At this

time, it is our position that the additional costs incurred as a result

of the flooding will offset the short-term benefits from nearly full

reservoirs.

Issue: Western should monitor actual losses on the transmission

system and update the loss factors used in its PRS in the future.

Response: We agree with this suggestion and will do this in the PRS

for the next FY.

Issue: Western should not use projected depletions beyond the cost

evaluation period.

Response: The position presented by the commenter points to the

fact the Bureau and Corps recognize projections of stream-flow

depletions which are unreliable. The quotes from the Bureau and the

Corps have been taken out of context. The statements made by the Bureau

and Corps are related to the short-term. During a drought, depletions

are higher than forecast, and during wet years, depletions are lower

than forecast. The long-term projections of depletions are based upon

normal usage. If we accept long-term development of future projects, we

must consider these depletions. Normal depletions would seem most

reasonable. We do not agree that projection of depletions can be

ignored when future projects are known to impact depletions.

Issue: Western should revise its other revenue projections in the

PRS to include additional revenues.

Response: The commenters pointed to three areas where they saw a

possibility of change:

1. Second-year revenues--The commenter had questioned the reduction

of special sales by approximately $7.5 million and the increased

Western Division transmission revenues of $1.7 million in the second-

year revenue projections.

The reduction of special sales revenues is an estimate based upon

the impact of reduced generation in the second year, which was an

expectation at the time of the estimate. Western feels it's appropriate

to leave the estimated projection. The second item is the projected

Western Division transmission revenue increases expected from the

proposed rate adjustment. We agree with this in principle; however, if

the rate adjustment is implemented as proposed, it has no significant

impact on the overall rate adjustment. It would reduce only the first

step of the rate adjustment by a few hundredths of a mill/kWh. Western

is not proposing to make the change for this rate adjustment; however,

in the future, when a transmission rate adjustment is being proposed at

the same time as a firm power rate adjustment, we will reflect proposed

changes in transmission revenues on a prospective basis rather than

after the fact.

2. Irrigation pumping rate--The commenter suggested that Western

should actively encourage Reclamation to promptly complete the studies

which could lead to a revision of the project-use pumping rates.

Western has been in contact with Reclamation concerning the

revision of their project-use rate. They have budgeted funds in FY 1994

to perform the ``ability to pay studies'' for their irrigation pumping

customers. We have provided study data which could define the rate

required to cover O&M and annual replacement expenses associated with

the power system. Western will continue to actively pursue this issue

with Reclamation.

3. Revenue from monthly sales over 60-percent load factor--The

future revenues from the ``tiered'' energy rate are not reflected in

the PRS. This is correct; however, the expense for purchasing this

energy is also not projected in the PRS. If Western were to project the

revenue for the monthly sales over 60-percent load factor, we would

need to project offsetting purchased power costs. Therefore, adding

these elements to the PRS is not rate impacting. We propose not to add

the elements to the current ratesetting study but to add them to future

PRSs for display purposes.

Issue: Western should project future interest rates in the PRS

instead of using the current-year rate for all future years.

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

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

states that forecasts for PRSs will utilize the rate for the latest

available year established by the Secretary of the Treasury and that

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

criteria used by the Department of the Treasury to determine the rate

each year.

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

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

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

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

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

volatile changes in the rate are mitigated through the blending

process.

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

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

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

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

resulted in higher revenue requirements. There is no assurance that

this would not happen again in the future.

Issue: Western should take an interest credit in the PRS for the

net cash balance accrued during the year for interest expense that is

not due and payable until yearend.

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

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

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

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

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

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

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

utilized by the power marketing agency.

The methodology for computing the interest offset varies between

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

used in making the interest calculation. The methodology employed by

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

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

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

credit is taken for interest collected and retained throughout the

year.

This methodology is based on the premise that interest expenses are

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

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

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

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

Accounting Office (GAO) in attachment 3 to a letter from DOE to the

Administrators of the five PMAs dated September 8, 1983.

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

PMAs (Bonneville Power Administration, Southwestern Power

Administration, Western Area Power Administration, and Southeastern

Power Administration) and provided a draft recommendation that DOE

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

computing interest credits. GAO summarized that Western was utilizing

reasonable business principles in the application of the interest

credit.

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

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

fair and reasonable credit against interest expenses.

Environmental Evaluation

In compliance with the National Environmental Policy Act of 1969,

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

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

Western has determined that this action is categorically excluded from

the preparation of an environmental assessment or an environmental

impact statement.

Executive Order 12866

DOE has determined that this is not a significant regulatory action

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

51735. Western has an exemption from centralized regulatory review

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

by the Office of Management and Budget is required.

Availability of Information

Information regarding these rate adjustments, including PRSs,

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

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

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

Power Administration, Division of Market Studies, Rates and Resources,

2525 4th Avenue North, Billings, Montana 59107-5800, telephone (406)

657-6488; Western Area Power Administration, Division of Marketing and

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

Power Administration, Office of the Assistant Administrator for

Washington Liaison, room 8G-061, Forrestal Building, 1000 Independence

Avenue SW., Washington, DC 20585.

Submission to Federal Energy Regulatory Commission

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

interim basis, together with supporting documents, will be promptly

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

Order

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

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

basis, effective the first day of the first full billing period

beginning on or after February 1, 1994, Rate Schedules P-SED-F6 and P-

SED-FP6 for the Pick-Sloan Missouri Basin Program-Eastern Division. The

rate schedules shall remain in effect on an interim basis, pending

Federal Energy Regulatory Commission confirmation and approval of them

or substitute rates on a final basis, through January 31, 1999.

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

Bill Whiten,

Deputy Secretary.

United States Department of Energy--Western Area Power

Administration

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

Pick-Sloan Missouri Basin Program--Eastern Division, Montana, North

Dakota, South Dakota, Minnesota, Iowa, Nebraska; Schedule of Rates for

Firm Power Service

Effective: First Step: The first day of the first full billing

period beginning on or after February 1, 1994, through September 30,

1994.

Second Step: Beginning on the first day of the first full billing

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

Available: Within the marketing area served by the Eastern Division

of the Pick-Sloan Missouri Basin Program.

Applicable: To the power and energy delivered to customers as firm

power service.

Character: Alternating current, 60 hertz, three phase, delivered

and metered at the voltages and points established by contract.

Monthly Rate:

First Step:

Demand Charge: $3.00 for each kilowatt per month (kW-month) of

billing demand.

Energy Charge: 7.76 mills for each kilowatthour (kWh) for all

energy delivered as firm power service. An additional charge of 3.38

mills per kWh (mills/kWh), for a total of 11.14 mills/kWh, will be

assessed for all energy delivered as firm power service that is in

excess of 60-percent monthly load factor and within the delivery

obligations under the provisions of the power sales contract.

Billing Demand: The billing demand will be as defined by the power

sales contract.

Second Step:

Demand Charge: $3.20 for each kW-month of billing demand.

Energy Charge: 8.32 mills for each kWh for all energy delivered as

firm power service. An additional charge of 3.38 mills/kWh for a total

of 11.70 mills/kWh will be assessed for all energy delivered as firm

power service that is in excess of 60-percent monthly load factor and

within the delivery obligations under the provisions of the power sales

contracts.

Billing Demand: The billing demand will be as defined by the power

sales contract.

Adjustments:

For Character and Conditions of Service: Customers who receive

deliveries at transmission voltage may in some instances be eligible to

receive a 5-percent discount on capacity and energy charges when

facilities are provided by the customer that result in a sufficient

savings to the United States to justify the discount. The determination

of eligibility for receipt of the voltage discount shall be exclusively

vested in the United States.

For Billing of Unauthorized Overruns: For each billing period in

which there is a contract violation involving an unauthorized overrun

of the contractual firm power and/or energy obligations, such overrun

shall be billed at 10 times the above rate.

For Power Factor: None. The customer will be required to maintain a

power factor at the point of delivery between 95-percent lagging and

95-percent leading.

United States Department of Energy--Western Area Power

Administration

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

Pick-Sloan Missouri Basin Program--Eastern Division, Montana, North

Dakota, South Dakota, Minnesota, Iowa, Nebraska; Schedule of Rates for

Firm Peaking Power Service

Effective: First Step: The first day of the first full billing

period beginning on or after February 1, 1994, through September 30,

1994.

Second Step: Beginning on the first day of the first full billing

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

Available: To the customers of the Billings Area Office with

generating resources enabling them to use firm peaking power service.

Applicable: To the power sold to customers as firm peaking power

service.

Character: Alternating current, 60 hertz, three phase, delivered

and metered at the voltages and points established by contract.

Monthly Rate:

First Step:

Demand Charge: $3.00 for each kilowatt per month (kW-month) of the

effective contract rate of delivery for peaking power or the maximum

amount scheduled, whichever is greater.

Energy Charge: 7.76 mills for each kilowatthour (kWh) for all

energy scheduled for delivery without return.

Billing Demand: The billing demand will be the greater of (1) the

highest 30-minute integrated demand measured during the month up to,

but not in excess of, the delivery obligation under the power sales

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

Second Step:

Demand Charge: $3.20 for each kW-month of the effective contract

rate of delivery for peaking power or the maximum amount scheduled,

whichever is greater.

Energy Charge: 8.32 mills for each kWh for all energy scheduled for

delivery without return.

Billing Demand: The billing demand will be the greater of (1) the

highest 30-minute integrated demand measured during the month up to,

but not in excess of, the delivery obligation under the power sales

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

Adjustments:

Billing for Unauthorized Overruns: For each billing period in which

there is a contract violation involving an unauthorized overrun of the

contractual obligation for peaking capacity and/or energy, such overrun

shall be billed at 10 times the above rate.

[FR Doc. 94-1487 Filed 1-19-94; 4:15 pm]

BILLING CODE 6450-01-P